UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-K

(Mark One)

R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2009
	For the fiscal year ended December 31, 2010
OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission File Number 1-4101

Tennessee Gas Pipeline Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware	74-1056569
(State or Other Jurisdiction of	(I.R.S. Employer
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
Incorporation or Organization)	Identification No.)
El Paso Building
1001 Louisiana Street
Houston, Texas	77002
(Address of Principal Executive Offices)	(Zip Code)

Telephone Number: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No R

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes R No £

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes £ No £

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. R

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer £

Accelerated filer £

Non-accelerated filer R

(Do not check if a smaller reporting company)

Smaller Reporting Company £

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No R

State the aggregate market value of the voting stock held by non-affiliates of the registrant: None

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.

Common Stock, par value $5 per share. Shares outstanding on ~~March~~ 1February 25, ~~2010~~2011: 208

TENNESSEE GAS PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

Documents Incorporated by Reference: None

TENNESSEE GAS PIPELINE COMPANY

TABLE OF CONTENTS

Caption			Page
PART I
Item 1.		Business	1
Item 1A.		Risk Factors	45
Item 1B.		Unresolved Staff Comments	1114
Item 2.		Properties	1114
Item 3.		Legal Proceedings	1114
Item 4.		~~Submission~~(Removed ofand ~~Matters to a Vote of Security Holders~~Reserved)	*14
PART II
Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	1114
Item 6.		Selected Financial Data	*
Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	1215
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk	1921
Item 8.		Financial Statements and Supplementary Data	2022
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	4344
Item 9A.		Controls and Procedures	4344
Item 9A(T).		Controls and Procedures	43
Item 9B.		Other Information	44
Item 9B.		Other Information	43
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		*
Item 11.	Executive Compensation		*
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		*
Item 13.	Certain Relationships and Related Transactions, and Director Independence		*
Item 14.	Principal Accountant Fees and Services		4445
PART IV
Item 15.		Exhibits and Financial Statement Schedules	4546
		Signatures	4647

____________

*	We have not included a response to this item in this document since no response is required pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

Below is a list of terms that are common to our industry and used throughout this document:

/d = per day MMBtu = million British thermal units BBtu = billion British thermal units MMcf = million cubic feet Bcf = billion cubic feet ~~NGL = natural gas liquid Dth = dekatherm~~ TBtu = trillion British thermal units LNG = liquefied natural gas ~~Tonne = metric tonne~~

When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

When we refer to “us”,” “we”,” “our”,” “ours”,” or “~~TGP”~~the company,” we are describing Tennessee Gas Pipeline Company and/or our subsidiaries.

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PART I

ITEM 1. BUSINESS

Overview and Strategy

We are a Delaware corporation incorporated in 1947, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our primary business consists of the interstate transportation and storage of natural gas. We conduct our business activities through our natural gas pipeline system and storage facilities as discussed below.

Our pipeline system and storage facilities operate under ~~tariffs~~a tariff approved by the Federal Energy Regulatory Commission (FERC) that ~~establish~~establishes rates, cost recovery mechanisms and other terms and conditions of services to our customers. The fees or rates established under our ~~tariffs~~tariff are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.

Our strategy is to enhance the value of our transportation and storage business by:

•

providing outstanding customer service;

• successfully executing ~~successfully~~on time and on ~~our~~budget ~~backlog~~for ofour committed expansion projects;

•

developing new growth projects in our market and supply areas;

•

maintaining the integrity and ensuring the safety of our pipeline system and other assets;

•

optimizing our contract portfolio;

• focusing on increasing utilization, efficiency and ~~synergies~~cost ~~across~~control in our ~~system~~operations; and

•

managing market segmentation and differentiation.

Pipeline System. Our pipeline system consists of approximately 1314,~~700~~100 miles of pipeline with a design capacity of approximately 7,208 MMcf/d. During ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008, average throughput was 45,~~614~~081 BBtu/d, 4,~~864~~614 BBtu/d, and 4,~~880~~864 BBtu/d. This multiple-line system begins in the natural gas producing regions of Louisiana, the Gulf of Mexico and south Texas and extends to the northeast section of the U.S., including the metropolitan areas of New York City and Boston. Our system also has interconnects at the U.S.- Mexico border and the U.S.- Canada border.

~~Underground~~FERC ~~Natural~~Approved ~~Gas Storage Facilities~~Project. ~~Along~~As ~~our~~of ~~pipeline~~December ~~system~~31, ~~we have approximately 92 Bcf of underground working natural gas storage capacity. Of this amount~~2010, 29we ~~Bcf~~had ~~is contracted~~the ~~from~~following ~~Bear~~significant ~~Creek~~FERC ~~Storage~~approved ~~Company,~~expansion ~~LLC~~project ~~(Bear~~on ~~Creek),~~ our ~~affiliate~~system. ~~Bear~~ ~~Creek,~~For ~~which~~a ~~owns~~further ~~and~~discussion ~~operates~~of another ~~underground~~expansion ~~natural~~projects, ~~gas~~see ~~storage~~Part ~~facility located~~II, inItem ~~Bienville Parish~~7, ~~Louisiana,~~Management’s isDiscussion ~~a joint venture equally owned by us~~ and ~~our~~Analysis ~~affiliate, Southern Natural Gas Company (SNG). The facility has 58 Bcf~~ of ~~working~~Financial ~~storage~~Condition ~~capacity that is committed equally to SNG~~ and usResults ~~under long-term~~of ~~contracts~~Operations.

Markets and Competition

Project	Capacity (MMcf/d)	Description	Anticipated Completion or In-Service Date

300 Line Project	350	To add 128 miles of pipeline, and approximately 55,000 horsepower of compression at two new compressor stations and at certain existing compressor stations	November 2011

~~Our~~Underground ~~customers consist~~Natural ofGas ~~natural~~Storage ~~gas~~Facilities. ~~distribution~~Along ~~and~~our ~~industrial~~pipeline ~~companies~~system, ~~electric generation~~we ~~companies,~~have ~~natural~~approximately ~~gas~~93 ~~producers,~~Bcf ~~other~~of underground working natural gas ~~pipelines~~storage ~~and natural~~capacity. ~~gas~~Of ~~marketing~~this ~~and~~amount, ~~trading~~29 ~~companies.~~Bcf Weis ~~provide~~contracted ~~transportation~~from ~~and storage~~Bear ~~services~~Creek inStorage ~~both~~Company, ~~our~~LLC ~~natural~~(Bear ~~gas~~Creek) ~~supply~~located ~~and~~in ~~market~~Bienville ~~areas~~Parish, Louisiana. Bear ~~Our~~Creek ~~pipeline system~~is ~~connects~~a ~~with~~joint ~~multiple~~venture ~~pipelines~~equally ~~that~~owned ~~provide~~by us and our ~~customers~~affiliate, ~~with~~Southern ~~access to~~Natural ~~diverse~~Gas ~~sources~~Company (SNG). The facility has 58 Bcf of ~~supply~~working ~~and~~storage ~~various~~capacity ~~natural~~that ~~gas~~is ~~markets~~committed equally to SNG and us.

The natural gas industry is undergoing a major shift in supply sources. Production from conventional sources is declining while production from unconventional sources, such as shale, tight sands, and coal bed methane, is rapidly increasing. This shift will change the supply patterns and flows on pipelines. The impact will vary among pipelines according to the proximity of the new supply sources. Our pipeline is connected to two major shale formations, the Haynesville in northern Louisiana and Texas and the Marcellus in Pennsylvania. It is likely that natural gas from these sources, will over time, replace receipts from traditional sources in south Texas and the Gulf of Mexico on our system. In addition, our system is close to the Eagle Ford shale formation in south Texas, which could be a major source of supply into the system in the future. This will affect the flows on the system and the array of shipper contracts.

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~~Another~~Markets ~~change in the supply patterns is the reduction in imports from Canada. This decrease has been the result of declining production~~ and increasing demand in Canada. This reduction has led to increased demand for domestic supplies and related transportation services, but it has been offset in part by imported LNG. Imported LNG has been a significant supply source for the North American market. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.Competition

~~Electric~~Our ~~power generation~~customers ~~has~~consist ~~been a growing demand sector~~ of ~~the~~ natural gas ~~market;~~distribution ~~however, this~~and ~~sector~~industrial ~~experienced~~companies, aelectric ~~decline~~generation incompanies, ~~demand in 2009 as a result of the downturn in the economy. We expect demand to return as the economy recovers. The growth of~~ natural gas~~-fired~~ ~~electric~~producers, ~~power~~other ~~benefits the~~ natural gas ~~industry~~pipelines ~~by creating~~and ~~more demand for~~ natural gas. ~~This~~marketing ~~potential~~and ~~benefit~~trading iscompanies. ~~offset,~~We ~~in varying~~provide ~~degrees,~~transportation byand ~~increased~~storage ~~generation~~services ~~efficiency,~~in ~~the~~both ~~more~~our ~~effective use of surplus electric capacity, increased~~ natural gas ~~prices~~supply and ~~the~~market ~~use and availability of other fuel sources for power generation~~areas. InOur ~~addition,~~pipeline insystem ~~several regions~~connects ofwith ~~the~~multiple ~~country,~~pipelines ~~new~~that ~~additions~~provide inour ~~electric~~customers ~~generating~~with ~~capacity~~access ~~have exceeded~~to ~~load~~diverse ~~growth~~sources ~~and electric transmission capabilities out~~ of ~~those regions.~~supply ~~These~~and ~~developments~~various ~~may inhibit owners of new power generation facilities from signing firm transportation contracts with~~ natural gas ~~pipelines~~ markets.

~~Growth~~The ~~of the~~ natural gas ~~market~~industry ~~has~~is ~~been~~undergoing ~~adversely~~a ~~affected~~major byshift ~~the current economic slowdown~~ in ~~the~~supply Usources.S. ~~and~~Production ~~global~~from ~~economies.~~conventional ~~The~~sources ~~decline~~is indeclining ~~economic~~while ~~activity~~production ~~reduced industrial~~from ~~demand~~unconventional ~~for~~sources, ~~natural~~such ~~gas~~as ~~and electricity~~shales, ~~which~~is ~~affected~~rapidly ~~natural~~increasing. ~~gas demand~~This ~~both~~shift ~~directly~~will inaffect ~~end-use~~the ~~markets~~supply ~~and~~patterns, ~~indirectly~~the ~~through~~flows ~~lower~~and ~~power generation~~the ~~demand~~rates ~~for~~that ~~natural~~can ~~gas.~~be Wecharged ~~expect~~on ~~the~~pipeline ~~demand~~systems. ~~and~~The ~~growth~~impact ~~for~~will ~~natural gas~~vary toamong ~~respond~~pipelines asaccording to the ~~economy~~location ~~recovers. Natural~~and ~~gas~~the ~~has~~number aof ~~favorable competitive~~competitors ~~position~~attached asto anthese ~~electric~~new ~~generation~~supply ~~fuel~~sources. ~~because~~Our itpipeline is aconnected ~~clean~~to ~~and abundant~~two ~~fuel~~major ~~with~~shale ~~lower~~formations: ~~capital~~the ~~requirements~~Haynesville ~~compared~~shale ~~with~~in ~~other~~northern ~~alternatives. The~~Louisiana ~~lower~~and ~~demand~~Texas and the ~~credit~~Marcellus ~~restrictions~~shale onin ~~investments~~Pennsylvania. It inis ~~the~~possible that ~~recent~~gas ~~past may~~from ~~slow~~these ~~development~~sources ofwill ~~supply~~increasingly ~~projects.~~displace ~~However,~~receipts weover ~~believe~~time ~~our~~from ~~exposure~~traditional ~~to changes~~sources in ~~natural~~south ~~gas~~Texas ~~consumption~~ and ~~demand~~the isGulf ~~largely~~of ~~mitigated~~Mexico byon aour ~~revenue base~~system. ~~that~~In addition, our system is ~~significantly~~near ~~comprised~~the ofEagle ~~long-term~~Ford ~~contracts~~shale ~~that~~formation ~~are~~in ~~based~~south ~~on firm~~Texas, ~~demand~~which ~~charges~~could ~~and~~be ~~are~~a ~~less~~major ~~affected~~source byof asupply ~~potential~~into ~~reduction~~the system in the ~~actual usage~~future orand ~~consumption~~could impact the flows on the system and the array of ~~natural~~shipper ~~gas~~contracts.

Another change in the supply patterns is the reduction in imports from Canada. This decrease has been the result of declining production and increasing demand in Canada. This reduction has led to increased demand for domestic supplies and related transportation services over the last several years, a trend which is expected to continue in the future. The increase in demand for gas and transportation caused by the trend in Canada could be partially offset by imports of LNG. Imports of LNG have fluctuated in the past in response to changing gas prices within North America, Europe and Asia. LNG terminals and other regasification facilities can serve as alternate sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.

Electric power generation has been the source of most of the growth in demand for natural gas over the last 10 years, and this trend is expected to continue in the future. The growth of natural gas in this sector is influenced by competition with coal and increased consumption of electricity as a result of recent economic growth. Short-term market shifts have been driven by relative costs of coal-fired generation versus gas-fired generation. A long-term market shift in the use of coal in power generation could be driven by environmental regulations. The future demand for natural gas could be increased by regulations limiting or discouraging coal use. However, natural gas demand could potentially be adversely affected by laws mandating or encouraging renewable power sources.

In response to changing market conditions, we have shifted from a traditional dependence solely on long-term contracts to an approach that balances short-term and long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new pipeline competition, shifts in supply sources, volatility in natural gas prices, demand for short-term capacity and new power generation markets.

~~Our~~We ~~existing transportation~~face ~~and~~competition ~~storage contracts mature at various times and~~ in ~~varying amounts~~all ~~of throughput capacity. Our ability to extend~~ our ~~existing~~market ~~customer contracts~~areas orand ~~remarket~~we ~~expiring~~compete ~~contracted~~with ~~capacity~~other isinterstate ~~dependent~~and onintrastate ~~competitive alternatives,~~pipelines ~~the~~for ~~regulatory~~deliveries ~~environment~~to atmultiple-connection ~~the~~customers ~~federal,~~who ~~state~~can ~~and~~take ~~local~~deliveries ~~levels and market supply and demand factors~~ at ~~the~~alternative ~~relevant~~points. ~~dates~~Natural ~~these~~gas ~~contracts~~delivered ~~are extended~~on orour ~~expire.~~system ~~The~~competes ~~duration~~with ofalternative ~~new~~energy orsources ~~renegotiated~~used ~~contracts~~to ~~will~~generate ~~be affected~~electricity bysuch ~~current~~as ~~prices~~hydroelectric power, ~~competitive~~coal ~~conditions~~ and ~~judgments~~fuel ~~concerning future market trends and volatility~~oil. ~~Subject~~In ~~to regulatory requirements~~addition, we ~~attempt~~ tocompete ~~recontract~~with orpipelines ~~remarket~~and ~~our~~gathering ~~capacity~~systems atfor ~~the~~connection ~~maximum~~to ~~rates~~new ~~allowed under~~supply ~~our~~sources ~~tariffs.~~in ~~However~~Texas, wethe ~~have~~Gulf ~~entered into a substantial portion~~ of ~~firm transportation~~Mexico, and ~~contracts~~the atemerging ~~amounts~~shale ~~that are less than these maximum allowable rates to remain competitive~~basins.

WeFor ~~face~~a ~~competition in~~further ~~all~~discussion ~~our~~of ~~market~~factors ~~areas~~impacting ~~and we compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on~~ our ~~system~~markets ~~competes with alternative energy sources used to generate electricity such as, hydroelectric power, coal~~ and ~~fuel oil. In addition~~competition, wesee ~~compete~~Item ~~with pipelines and gathering systems for connection to new supply sources in Texas~~1A, ~~the~~Risk ~~Gulf of Mexico, and the emerging shale basins~~Factors.

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~~The~~Customers ~~following table details our customer~~ and contract information related to our pipeline system as of December 31, 2009. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.Contracts

Customer Information	Contract Information
Approximately 470 firm and interruptible customers.	Approximately 510 firm transportation contracts. Weighted average remaining contract term of approximately four years.
Major Customer: National Grid USA and Subsidiaries (766 BBtu/d)	Expire in 2011-2029.

Our existing transportation and storage contracts expire at various times and in varying amounts of throughput capacity. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Although we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariff, we frequently enter into firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive.

The following table details our customer and contract information related to our pipeline system as of December 31, 2010. Firm customers reserve capacity on our pipeline system and storage facilities and are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they transport, store, inject or withdraw.

Customer Information		Contract Information

Approximately 410 firm and interruptible customers.		Approximately 470 firm transportation contracts. Weighted average remaining contract term of approximately four years.

Major Customer: National Grid USA and subsidiaries (495 BBtu/d) (332 BBtu/d)		Expire in 2012-2013. Expire in 2014-2029.

Regulatory Environment

Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and other terms and conditions of services to our customers. The rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital. Generally, the FERC’s authority extends to:

•

rates and charges for natural gas transportation and storage;

•

certification and construction of new facilities;

•

extension or abandonment of services and facilities;

•

maintenance of accounts and records;

•

relationships between pipelines and certain affiliates;

•

terms and conditions of service;

•

depreciation and amortization policies;

•

acquisition and disposition of facilities; and

•

initiation and discontinuation of services.

Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of the Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations.3

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Environmental

A description of our environmental remediation activities is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.

Employees

As of February 2321, ~~2010~~ 2011, we had approximately 1,~~630~~675 full-time employees, none of whom are subject to a collective bargaining arrangement.

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ITEM 1A. RISK FACTORS

CAUTIONARY STATEMENT FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

~~THE PRIVATE~~This ~~SECURITIES~~report ~~LITIGATION~~contains ~~REFORM~~forward-looking ~~ACT~~statements OFwithin the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from the actual results and such variances can be material. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these and other cautionary statements. We disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date provided. With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. If any of the following risks were actually to occur, our business, results of operations, financial condition and growth could be materially adversely affected.

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

With this in mind, you should consider the risks discussed elsewhere in this report and other documents we file with the Securities and Exchange Commission (SEC) from time to time and the following important factors that could cause actual results to differ materially from those expressed in any forward-looking statement made by us or on our behalf.

Risks Related to Our Business

~~Our~~The success of our business depends on many factors beyond our control.

The ~~financial~~ results of our ~~transportation~~business ~~and~~are ~~storage~~impacted ~~operations~~in ~~are~~the ~~impacted~~long term by the volumes of natural gas we transport or store and the prices we are able to charge for ~~doing~~ sothese services. The volumes ~~of natural gas~~ we ~~are able to~~ transport and store ~~depends~~ depend on the actions of third parties ~~and~~that are based on factors beyond our control. Such ~~actions~~factors include ~~factors~~ events that negatively impact our customers’ demand ~~and~~for ~~producers’~~natural ~~supply,~~gas ~~including factors~~and ~~that~~could ~~negatively~~expose ~~impact~~ our ~~customers’~~pipeline ~~need~~to ~~for~~the ~~natural~~risk ~~gas~~that ~~from~~we ~~us,~~will ~~as well~~not asbe ~~the~~able ~~continued~~to ~~availability~~renew ofcontracts ~~natural~~at ~~gas~~expiration ~~production~~or ~~and~~that ~~reserves connected~~we will be required to discount our ~~pipeline~~rates ~~system~~significantly upon renewal. ~~Further,~~We ~~the~~are ~~following~~also ~~factors, most~~highly ofdependent ~~which~~on ~~are~~our ~~also~~customers ~~beyond~~and downstream pipelines to attach new and increased loads on their systems in order to grow our ~~control~~business. Further, ~~may~~state ~~unfavorably~~agencies ~~impact~~that regulate our ~~ability~~local ~~to maintain~~distribution orcompany ~~increase~~customers ~~current~~could ~~throughput,~~impose orrequirements tothat ~~remarket~~could ~~unsubscribed~~impact ~~capacity~~demand on for our ~~pipeline system:~~services.

•The ~~service~~volume ~~area~~of ~~competition;~~gas that we transport and store also depends on the availability of natural gas supplies that are attached to our pipeline system, including the need for producers to continue to develop additional gas supplies to offset the natural decline from existing wells connected to our system. This requires the development of additional natural gas reserves, obtaining additional supplies from interconnecting pipelines, and the development of LNG facilities on or near our system. There have been major shifts in supply basins over the last few years, especially with regard to the development of new natural gas shale plays and declining production from conventional sources of supplies as well as declining deliveries from Canada. A prolonged decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission and storage through our system.

•Furthermore, ~~price~~our ~~competition;~~ability to deliver gas to our shippers is dependent upon their ability to purchase and deliver gas at various receipt points into our system. On occasion, particularly during extreme weather conditions, the gas delivered by our shippers at the receipt points into our system is less than the gas that they take at delivery points from our system. This can cause operational problems and can negatively impact our ability to meet our shippers’ demand.

•The ~~changes~~agencies inthat ~~regulation~~regulate us and ~~actions~~our ofcustomers ~~regulatory~~could ~~bodies;~~affect our profitability.

•Our ~~weather~~business is extensively regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior, the U.S. Coast Guard, the U.S. Department of Homeland Security and various state and local regulatory agencies whose actions have the potential to adversely affect our profitability. The FERC regulates most aspects of our business, including the terms and conditions of services offered, our relationships with affiliates, construction and abandonment of facilities and the rates charged by our pipeline (including establishing authorized rates of return). We periodically file to adjust the rates charged to our customers. In 2010, we filed a rate case that will establish new rates in 2011. There is a risk that the FERC may establish rates that are not acceptable to us and have a negative impact ~~natural~~on ~~gas~~us. ~~throughput~~In addition, our profitability is influenced by fluctuations in costs and ~~storage~~our ~~levels;~~ability to recover any increases in our costs in the rates charged to our shippers. Our operating results can be negatively impacted to the extent that such costs increase in an amount greater than what we are permitted to recover in our rates or to the extent that there is a lag before we can file and obtain rate increases.

• weather fluctuations or warming or cooling trends that may impact demand in the markets in which we do business, including trends potentially attributable to climate change;

• continued development of additional sources of gas supply that can be accessed;

• decreased natural gas demand due to various factors, including economic recession (as further discussed below), availability of alternate energy sources and increases in prices;

• legislative, regulatory or judicial actions, such as mandatory renewable portfolio standards and greenhouse gas (GHG) regulations and/or legislation that could result in (i) changes in the demand for natural gas and oil, (ii) changes in the availability of or demand for alternative energy sources such as hydroelectric and nuclear power, wind and solar energy and/or (iii) changes in the demand for less carbon intensive energy sources;

• availability and cost to fund ongoing maintenance and growth projects, especially in periods of prolonged economic decline;

• opposition to energy infrastructure development, especially in environmentally sensitive areas;

• adverse general economic conditions including prolonged recessionary periods that might negatively impact natural gas demand and the capital markets;

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• our ability to achieve targeted annual operating and administrative expenses primarily by reducing internal costs and improving efficiencies from leveraging a consolidated supply chain organization; and

• unfavorable movements in natural gas prices in certain supply and demand areas.

A substantial portion of our revenues are generated from firm transportation contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. Currently, a substantial portion of our revenues are under contracts that are discounted at rates below the maximum rates allowed under our tariff. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control as discussed in more detail above. In addition, changes in state regulation of local distribution companies may cause us to negotiate short-term contracts or turn back our capacity when our contracts expire.

For 2009, our revenues from National Grid USA and Subsidiaries represented approximately 12 percent of our operating revenues. For additional information on our revenues from this customer, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10. The loss of this customer or a decline in its creditworthiness could adversely affect our results of operations, financial position and cash flows.

We are exposed to the credit risk of our customers and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk of delays in payment as well as losses resulting from nonpayment and/or nonperformance by our customers, including default risk associated with adverse economic conditions. Our credit procedures and policies may not be adequate to fully eliminate customer credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future customers fail to pay and/or perform and we are unable to remarket the capacity, our business, the results of our operations and our financial condition could be adversely affected. We may not be able to effectively remarket capacity during and after insolvency proceedings involving a shipper.

A portion of our transportation services are provided pursuant to long-term, fixed-price “negotiated rate” contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.

It is possible that costs to perform services under “negotiated rate” contracts will exceed the negotiated rates. Under FERC policy, a regulated service provider and a customer may mutually agree to sign a contract for service at a “negotiated rate” which may be above or below the FERC regulated “recourse rate” for that service, and that contract must be filed and accepted by FERC. These “negotiated rate” contracts are not generally subject to adjustment for increased costs which could be produced by inflation, cost of capital, taxes or other factors relating to the specific facilities being used to perform the services. Any shortfall of revenue, representing the difference between “recourse rates” (if higher) and negotiated rates, under current FERC policy is generally not recoverable from other shippers.

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and natural gas reserves and obtaining additional supplies from interconnecting pipelines, primarily in the emerging shale basins. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of reserves available for transportation and storage through our system.

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WeOur ~~retain~~existing arates ~~fixed percentage~~may ofalso ~~natural~~be ~~gas~~challenged ~~transported~~by ~~as provided in our tariff~~complaint. ~~This~~The ~~retained natural~~FERC ~~gas~~commenced isseveral ~~used~~proceedings asin ~~fuel~~2009 and to2010 ~~replace~~against ~~lost~~unaffiliated ~~and~~pipeline ~~unaccounted~~systems ~~for natural gas. We are at risk if we retain less natural gas than needed for fuel and~~ to ~~replace lost~~reduce ~~and unaccounted for natural gas. Pricing volatility may impact~~ the ~~value~~rates ~~of under~~they orwere ~~over~~charging ~~recoveries~~their ~~of retained natural gas, imbalances and system encroachments~~customers. IfThere ~~natural~~is ~~gas~~a ~~prices~~risk inthat the ~~supply~~FERC ~~basins~~or ~~connected to~~ our ~~pipeline~~ ~~system~~customers ~~are~~could ~~higher~~file ~~than~~similar ~~prices~~complaints inon ~~other~~us ~~natural~~and ~~gas~~that ~~producing regions, our ability to compete with other transporters may be negatively impacted on~~ a ~~short-term~~ ~~basis,~~successful ascomplaint ~~well~~against ~~as with respect to~~ our ~~long-term~~rates ~~recontracting activities.~~could ~~Furthermore,~~have ~~fluctuations~~an inadverse ~~pricing between supply sources and market areas could negatively~~ impact ~~our~~on ~~transportation revenues~~us. For ~~Consequently,~~ a ~~significant~~discussion ~~prolonged~~of ~~downtown~~our inrecent ~~natural~~rate ~~gas~~case ~~prices~~filed ~~could~~with ~~have~~the aFERC, ~~material adverse~~see ~~effect~~Part onII, ~~our~~Item ~~financial condition~~8, ~~results~~Financial ofStatements ~~operations~~ and ~~liquidity. Fluctuations~~Supplementary inData, ~~energy~~Note ~~prices are caused by a number of factors, including:~~8.

•Certain ~~regional,~~of ~~domestic~~our ~~and~~transportation ~~international~~services ~~supply~~are ~~and~~subject ~~demand,~~to ~~including~~negotiated ~~changes~~rate incontracts ~~supply~~that ~~and~~may ~~demand~~not ~~due~~allow us to ~~general~~recover ~~economic~~our ~~conditions~~costs ~~and~~of ~~weather;~~providing the services.

•Under ~~availability~~FERC policy, interstate pipelines and ~~adequacy~~their customers may execute contracts at a negotiated rate which may be above or below the FERC regulated recourse rate for that service. These negotiated rate contracts are generally not subject to adjustment for increased costs which could occur due to inflation, increases in the cost of ~~gathering~~capital or taxes or other factors relating to the specific facilities being used to perform the services. It is possible that costs to perform services under negotiated rate contracts will exceed the negotiated rates. Any shortfall of revenue, ~~processing~~representing the difference between recourse rates and ~~transportation~~negotiated ~~facilities;~~rates could result in either losses or lower rates of return in providing such services.

•Our ~~energy~~revenues ~~legislation~~are ~~and~~generated ~~regulation,~~under ~~including~~contracts ~~potential~~that ~~changes~~must ~~associated~~be ~~with~~renegotiated ~~GHG emissions and renewable portfolio standards;~~periodically.

•Our ~~federal~~revenues are generated under transportation and ~~state~~storage ~~taxes~~contracts which expire periodically and must be renegotiated, ifextended ~~any~~or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. For example, basis differentials between receipt and delivery points on ~~the~~our ~~sale~~pipeline orsystem ~~transportation~~could decrease over time and ~~storage~~thereby ofnegatively ~~natural~~impact ~~gas~~our ability to renew contracts at rates that were previously in place. Our ability to extend and ~~NGL;~~replace contracts could be adversely affected by factors we cannot control, as discussed above. In addition, changes in state regulation of local distribution companies may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire.

•The ~~the~~expansion ~~price~~of ~~and~~our ~~availability~~pipeline ofsystem ~~supplies~~by ofconstructing ~~alternative~~new ~~energy~~facilities ~~sources;~~subjects us to construction and other risks that may adversely affect us.

•We ~~the~~frequently ~~level~~expand ~~of imports, including~~ the ~~potential~~capacity ~~impact~~ of ~~political~~our ~~unrest~~existing ~~among~~pipeline ~~countries producing oil~~ and ~~LNG,~~storage asfacilities ~~well~~by asconstructing ~~the~~additional ~~ability~~facilities. Construction of ~~certain~~these ~~foreign~~facilities ~~countries~~is subject to ~~maintain~~various ~~natural~~regulatory, ~~gas~~development and ~~oil~~operational ~~prices~~risks, ~~production and export controls.~~including:

~~The~~• our ability to obtain necessary approvals and permits from the FERC and other regulatory agencies on a timely basis that ~~regulate~~ are on terms that are acceptable to us, including the potential negative impact of delays and ~~our~~increased ~~customers~~costs ~~could~~caused ~~affect~~by ~~our profitability.~~general opposition to energy infrastructure development, especially in environmentally, culturally sensitive and more heavily populated areas;

~~Our~~• ~~business is regulated by~~ the ~~FERC,~~ability ~~the~~to ~~U.S.~~access ~~Department~~sufficient ofcapital ~~Transportation,~~at ~~the~~reasonable ~~U.S. Department~~rates ~~of the Interior and various state and local regulatory agencies whose actions have the potential~~ to ~~adversely~~fund ~~affect~~expansion ~~our profitability. In particular~~projects, ~~the~~ ~~FERC~~especially ~~regulates~~in ~~the~~periods ~~rates~~of weprolonged ~~are~~economic ~~permitted~~decline towhen ~~charge~~we ~~our~~may ~~customers~~be ~~for~~unable ~~our services~~to ~~and~~access ~~sets~~the ~~authorized~~capital ~~rates of return.~~markets;

We• ~~periodically file with~~ the ~~FERC~~availability ~~to adjust the rates charged to our customers. In establishing those rates, the FERC uses a discounted cash flow model that incorporates the use~~ of ~~proxy~~skilled groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. Depending on the specific risks faced by us and the companies included in the proxy grouplabor, ~~the FERC may establish rates that are not acceptable to us and have a negative impact on our cash flows~~equipment, ~~profitability~~ and ~~results~~ ofmaterials ~~operations. In addition, pursuant~~ to ~~laws~~complete ~~and~~expansion regulations, our existing rates may be challenged by complaint. The FERC commenced several complaint proceedings in 2009 against unaffiliated pipeline systems to reduce the rates they were charging their customers. There is a risk that the FERC or our customers could file similar complaints on our pipeline system and that a successful complaint against our rates could have an adverse impact on our cash flows and results of operations.projects;

~~Also,~~• ~~increased regulatory~~potential ~~requirements~~changes ~~relating to the integrity of our pipeline requires additional spending~~ in ~~order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures. Further~~federal, state ~~agencies~~and ~~that regulate our~~ local ~~distribution~~ ~~company~~statutes, ~~customers~~regulations, ~~could~~and ~~impose requirements that could impact demand for our services.~~orders;

•

impediments on our ability to acquire rights-of-way or land rights on terms that are acceptable to us;

•

our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from weather conditions, geologic conditions, inflation or increased costs of equipment, materials (such as steel and nickel), labor, contractor productivity, delays in construction due to various factors including delays in obtaining regulatory approvals or other factors beyond our control. These cost overruns could be material and we may not be able to recover such excess costs from our customers which could negatively impact the return on our investments or could result in financial impairments;

•

our ability to construct projects within anticipated time frames that would likely delay our collection of transportation charges under our contracts;

•

the failure of suppliers and contractors to meet their performance and warranty obligations; and

•

the lack of transportation, storage or throughput commitments.

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~~Environmental compliance~~Any ~~and~~of ~~remediation~~these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. There is also the risk that a downturn in the economy and its negative impact upon natural gas demand may result in either slower development in the ~~costs~~potential offor ~~environmental~~future ~~liabilities~~expansion ~~could exceed~~projects or adjustments in the contractual commitments supporting such projects. As a result, new facilities may be delayed or may not achieve our ~~estimates~~expected investment return.

~~Our~~We ~~operations~~depend are subject to various environmental laws and regulations regarding compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on ~~our~~a ~~operations.~~key ~~Remediation obligations~~customer ~~can~~for ~~result~~a in significant ~~costs~~portion ~~associated with the investigation or clean-up~~ of ~~contaminated~~our ~~properties~~revenues ~~(some of which have been designated as Superfund sites by the U.S. Environmental Protection Agency (EPA) under the Comprehensive Environmental Response, Compensation~~ and ~~Liability Act), as well as damage claims arising out of~~ the ~~contamination~~loss of ~~properties~~this orkey ~~impact~~customer on natural resources. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could beresult ~~required~~in toa ~~set~~decline ~~aside~~in ~~additional amounts which could significantly impact~~ our ~~future consolidated results of operations, financial position, or cash flows~~revenues. ~~See Part II, Item 8, Financial Statements and Supplementary Data, Note 8.~~

InWe ~~estimating~~rely on a key customer for a significant portion of our ~~environmental~~ ~~liabilities~~revenues. For the year ended December 31, we2010, ~~face~~National ~~uncertainties~~Grid ~~that~~USA ~~include:~~and subsidiaries accounted for approximately 14 percent of our operating revenues. The loss of any material portion of the contracted volumes of this customer, as a result of competition, creditworthiness, inability to negotiate extensions, or replacements of contracts or otherwise, could have a material adverse effect on us. For additional information on our revenues from this customer, see Part II, Item 8, Financial Statements and Supplementary Data, Note 10.

•The ~~estimating~~costs ~~pollution~~to ~~control and clean up costs~~maintain, ~~including~~repair ~~sites~~and ~~where~~replace ~~preliminary~~our ~~site~~pipeline ~~investigation~~system ormay ~~assessments~~exceed ~~have~~our ~~been~~expected ~~completed;~~levels.

•Much ~~discovering~~of ~~new~~our ~~sites~~pipeline infrastructure was originally constructed many years ago. The age of these assets may result in them being more costly to maintain and repair. We may also be required to replace certain facilities over time. In addition, our pipeline assets may be subject to the risk of failures or ~~additional~~other ~~information~~incidents due to factors outside of our control (including due to third party excavation near our pipeline, unexpected degradation of our pipeline, as well as design, construction or manufacturing defects) that could result in personal injury or property damages. Much of our pipeline system is located in populated areas which increases the level of such risks. Such incidents could also result in unscheduled outages or periods of reduced operating flows which could result in a loss of our ability to serve our customers and a loss of revenues. Although we are targeted to complete our pipeline integrity program which includes the development and use of in-line inspection tools in high consequence areas by its required completion date at ~~existing~~the ~~sites;~~end of 2012, we will continue to incur substantial expenditures beyond 2012 relating to the integrity and safety of our pipeline. In addition, as indicated above there is a risk that new regulations associated with pipeline safety and integrity issues will be adopted that could require us to incur additional material expenditures in the future. There is also a risk of gas loss and field degradation for our storage operations.

•We ~~forecasting~~do ~~cash~~not ~~flow~~own ~~timing~~all toof ~~implement~~the ~~proposed~~land ~~pollution~~on ~~control~~which our pipeline and ~~cleanup~~facilities ~~costs;~~are located, which could disrupt our operations.

•We ~~receiving~~do ~~regulatory~~not ~~approval~~own ~~for~~all ~~remediation~~of ~~programs;~~the land on which our pipeline and facilities are located. We are subject to the risk that we do not have valid rights-of-way, that such rights-of-way may lapse or terminate, our facilities may not be properly located within the boundaries of such rights-of-way or the landowners otherwise interfere with our operations. Our loss of or interference with these rights could have a material adverse effect on us.

•There ~~quantifying~~are ~~liability~~accounting ~~under~~principles ~~environmental laws~~ that ~~may~~are ~~impose~~unique ~~joint~~to ~~and~~regulated ~~several~~interstate ~~liability~~pipeline onassets ~~potentially~~that ~~responsible~~could ~~parties~~materially ~~and~~impact ~~managing~~our ~~allocation~~recorded ~~responsibilities;~~earnings.

•Accounting ~~evaluating~~policies ~~and~~for ~~understanding~~FERC ~~environmental~~regulated ~~laws~~pipelines ~~and~~are ~~regulations~~in certain instances different from U.S. generally accepted accounting principles (GAAP) for non-regulated entities. For example, FERC accounting policies permit certain regulatory assets to be recorded on our balance sheet that would not typically be recorded for non-regulated entities. In determining whether to account for regulatory assets on our pipeline, we consider various factors including ~~their~~regulatory ~~interpretation~~changes and ~~enforcement;~~the impact of competition to determine the probability of recovery of these assets. Currently, we have regulatory assets recorded on our balance sheet. If we determine that future recovery is no longer probable, then we could be required to write off the regulatory assets in the future. In addition, we capitalize a carrying cost (AFUDC) on equity funds related to our construction of long-lived assets. Equity amounts capitalized are included as other income on our income statement. To the extent that one of our expansion projects is not fully subscribed when it goes into service, we may experience a reduction in our earnings once the pipeline is placed into service.

• interpreting whether various maintenance activities performed in the past and currently being performed required pre-construction permits pursuant to the Clean Air Act; and

• changing environmental laws and regulations that may increase our costs.

In addition to potentially increasing the cost of our environmental liabilities, changing environmental laws and regulations may increase our future compliance costs, such as the costs of complying with ozone standards, emission standards with regard to our reciprocating internal combustion engines on our pipeline system, GHG reporting and potential mandatory GHG emissions reductions. Future environmental compliance costs relating to GHGs associated with our operations are not yet clear. For a further discussion on GHGs, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, Commitments and Contingencies.

Although it is uncertain what impact legislative, regulatory, and judicial actions might have on us until further definition is provided in those forums, there is a risk that such future measures could result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances or pay taxes related to our GHG and other emissions, and (v) administer and manage an emissions program for GHG and other emissions. Changes in regulations, including adopting new standards for emission controls from certain of our facilities, could also result in delays in obtaining required permits to construct or operate our facilities. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipeline and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

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~~Our~~The ~~operations are~~supply ~~subject~~and todemand ~~operational~~for ~~hazards~~natural ~~and~~gas ~~uninsured~~could ~~risks~~be adversely affected by many factors outside of our control which could negatively affect us.

Our ~~operations~~success ~~are subject~~depends toon the ~~inherent~~supply ~~risks~~and ~~normally~~demand ~~associated~~for ~~with~~natural ~~pipeline~~gas. The ~~operations, including~~degree ~~pipeline~~to ~~failures,~~which ~~explosions,~~our ~~pollution,~~business ~~release~~is ofimpacted ~~toxic~~by ~~substances~~changes in supply or demand varies. For example, ~~fires,~~ ~~adverse~~we ~~weather~~are ~~conditions~~not ~~(such~~significantly asimpacted ~~hurricanes~~in ~~and~~the ~~flooding),~~short-term ~~terrorist activity~~by reductions in the supply or ~~acts~~demand offor ~~aggression,~~natural ~~and~~gas ~~other~~since ~~hazards.~~we ~~Each~~recover most of ~~these~~our ~~risks~~revenues ~~could result~~from inreservation ~~damage~~charges tounder orlonger-term ~~destruction~~contracts that are not dependent on the supply and demand of natural gas in the short-term. However, our ~~facilities~~business orcan ~~damages~~be ornegatively ~~injuries~~impacted ~~to persons~~by ~~and~~sustained ~~property~~downturns ~~causing~~in ussupply toand ~~suffer~~demand ~~substantial~~for ~~losses~~natural gas. InOne ~~addition, although~~of the major factors that will impact natural gas demand will be the potential ~~effects~~growth of ~~climate~~natural ~~change~~gas onin ~~our~~the ~~operations~~power ~~(such~~generation ~~as hurricanes~~market, ~~flooding,~~particularly ~~etc.)~~driven ~~are~~by ~~uncertain~~the atspeed ~~this~~and ~~time,~~level ~~changes~~of inexisting ~~climate patterns~~coal-fired aspower ageneration ~~result~~that ofis ~~global~~replaced ~~emissions~~with ofnatural ~~GHG~~gas-fired ~~could~~power ~~have~~generation. In aaddition, ~~negative~~the ~~impact~~supply and demand for natural gas for our business will depend on many other factors outside of our ~~operations~~control, inwhich ~~the~~include, ~~future.~~among others:

~~While~~• weadverse ~~maintain insurance~~changes ~~against many of these risks to the extent and~~ in ~~amounts~~global ~~that~~economic ~~we believe are reasonable~~conditions, ~~our~~including insurance coverages have material deductibles as well as limits on our maximum recovery, and do not cover all risks. There is also the risk that our coverages will change over time in light of increased premiums or changes ~~in the terms of the insurance coverages~~ that ~~could~~negatively ~~result~~impact ~~in our~~general ~~decision~~demand tofor ~~either~~power ~~terminate~~generation ~~certain~~and ~~coverages,~~industrial ~~increase~~loads ~~our~~for ~~deductibles~~natural or decrease our maximum recoveries. In addition, there is a risk that our insurers may default on their coverage obligations. As a result, our results of operations, cash flows or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.gas;

~~The~~• ~~expansion~~adverse ~~of our~~changes ~~business~~in bygeopolitical ~~constructing~~factors ~~new~~and ~~facilities~~unexpected ~~subjects~~wars, usterrorist toactivities ~~construction~~ and ~~other~~ ~~risks~~others ~~that~~acts ~~may~~of ~~adversely affect our financial results.~~aggression;

We• ~~may~~technological ~~expand~~advancements ~~the capacity~~that ofmay ~~our~~drive ~~existing~~further ~~pipeline~~increases orin ~~storage~~production ~~facilities~~from bynatural ~~constructing additional~~gas ~~facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:~~shales;

• ~~our~~competition ~~ability~~from toimported ~~obtain~~LNG ~~necessary approvals~~ and ~~permits~~Canadian bysupplies ~~the FERC~~ and ~~other~~alternate regulatory agencies on a timely basis and on terms that are acceptable to us, including the potential impact of delays and increased costs caused by certain environmental and landowner groups with interests along the route of our pipelinefuels;

• ~~the~~increased ~~ability~~prices ~~to access sufficient capital at reasonable rates to fund expansion projects, especially in periods~~ of ~~prolonged~~natural ~~economic~~gas ~~decline~~that ~~when~~could wenegatively ~~may~~impact ~~be unable to access the capital markets~~demand;

• ~~the~~increased ~~availability~~costs ~~of skilled labor, equipment, and materials~~ to ~~complete~~transport ~~expansion~~natural ~~projects~~gas;

• ~~potential~~adoption ~~changes~~of invarious ~~federal,~~energy ~~state~~efficiency and ~~local~~conservation ~~statutes,~~measures; ~~regulations~~ and ~~orders, such as environmental requirements, including climate change requirements, that delay or prevent a project from proceeding or increase the anticipated cost of the project;~~

• ~~impediments~~perceptions ~~on our ability to acquire rights-~~of~~-way~~ orcustomers ~~land~~on ~~rights~~the oravailability ~~to commence~~ and ~~complete~~price ~~construction~~volatility onof anatural ~~timely~~gas ~~basis~~prices orover onthe ~~terms that are acceptable to us;~~longer-term.

•The ~~our~~price ~~ability~~for tonatural ~~construct~~gas ~~projects~~could ~~within~~be ~~anticipated~~adversely ~~costs,~~affected ~~including~~by ~~the~~many ~~risk~~factors ~~that~~outside ~~we may incur cost overruns resulting from inflation or increased costs~~ of ~~equipment, materials, labor, contractor productivity, delays in construction or other factors beyond~~ our control, ~~that we may not be able to recover from our customers~~ which ~~may~~could benegatively ~~material;~~affect us.

•Our success depends upon the ~~lack~~prices ofwe ~~future~~receive ~~growth~~for inour natural gas. Natural ~~supply~~gas prices historically have been volatile and~~/or~~ ~~demand;~~are likely to continue to be volatile in the future, especially given current global geopolitical and economic conditions. There is a risk that commodity prices will remain depressed for sustained periods, especially in relation to natural gas prices which are at relatively low levels at this time. The degree to which our business is impacted by lower commodity prices varies. For example, we are not significantly impacted in the short-term by changes in natural gas prices. However, we can be negatively impacted in the long-term by sustained depression in commodity prices for natural gas, including reductions in our ability to renew transportation contracts on favorable terms, as well as to construct new pipeline infrastructure. The price for natural gas is subject to a variety of additional factors that are outside of our control, which include, among others:

• ~~the~~changes ~~lack~~in ofregional ~~transportation,~~and ~~storage~~domestic orsupply ~~throughput~~and ~~commitments.~~demand;

~~Any~~• ofchanges ~~these~~in ~~risks could~~basis ~~prevent~~differentials aamong ~~project~~different ~~from~~supply ~~proceeding,~~basins ~~delay its completion or increase its anticipated costs. There is also the risk~~ that ~~the~~can ~~downturn~~negatively ~~in the economy and its negative~~ impact ~~upon~~our ~~natural~~ability ~~gas~~to ~~demand~~compete ~~may~~with ~~result~~supplies infrom ~~either~~other ~~slower development~~basins, inincluding our ~~expansion~~ability ~~projects~~to ormaintain ~~adjustments~~transportation inrevenues ~~the~~and ~~contractual commitments~~renew ~~supporting~~transportation ~~such~~contracts ~~projects.~~in Assupply abasins ~~result,~~that ~~new~~are ~~facilities may be delayed or we may~~ not ~~achieve~~as ~~our~~competitive ~~expected~~as ~~investment~~other ~~return, which could adversely affect our results of operations, cash flows or financial position.~~alternatives;

~~Our~~• ~~business requires~~changes ~~the~~in ~~retention and recruitment of a skilled workforce and~~ the ~~loss~~costs of ~~employees~~ ~~could~~transporting ~~result~~natural ~~in the failure to implement our business plan.~~gas;

~~Our~~• ~~business requires~~increased ~~the~~federal ~~retention~~ and ~~recruitment~~state oftaxes, aif ~~skilled workforce. If we are unable to retain and recruit employees such as engineers and other technical personnel~~any, ~~our~~ ~~business~~on ~~could~~the betransportation ~~negatively~~of ~~impacted.~~natural gas;

•

the price and availability of supplies of alternative energy sources; and

•

the amount of capacity available to transport natural gas.

Our business is subject to competition from third parties which could negatively affect us.

The natural gas business is highly competitive. We compete with other interstate and intrastate pipeline companies as well as gatherers and storage companies in the transportation and storage of natural gas. We also compete with suppliers of alternate sources of energy, including electricity, coal and fuel oil. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes growing competition in many of the markets that we serve, including many of the markets in the northeast.

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~~Adverse~~Our ~~general domestic~~operations ~~economic~~are ~~conditions~~subject ~~could~~to ~~negatively~~operational ~~affect~~hazards ~~our~~and ~~operating results,~~uninsured ~~financial~~risks ~~condition~~which orcould ~~liquidity~~negatively affect us.

WeOur operations are subject to the inherent risks including fires, Elearthquakes, ~~Paso~~adverse weather conditions (such as extreme cold or heat, hurricanes, tornadoes, lightning and ~~its~~ ~~subsidiaries~~flooding) ~~are~~and ~~subject~~other tonatural disasters; terrorist activity or acts of aggression; the ~~risks~~collision ~~arising~~of ~~from~~equipment ~~adverse~~of ~~changes~~third ~~in general~~parties ~~domestic~~on ~~economic~~our ~~conditions~~infrastructure (such as damage caused to our underground pipeline by third party excavation or construction); explosions, pipeline failures, mechanical and process safety failures, events causing our facilities to operate below expected levels of capacity or efficiency; uncontrollable flows of natural gas, release of pollution or contaminants into the environment (including ~~recession~~discharges of toxic gases or ~~economic~~substances) ~~slowdown~~and other environmental hazards. ~~The~~ ~~global~~Each ~~economy~~of isthese ~~experiencing~~risks could result in (a) ~~recession~~damage ~~and~~or ~~the~~destruction ~~financial~~of ~~markets~~our ~~have experienced~~facilities, ~~extreme~~(b) ~~volatility~~damages and ~~instability~~injuries to persons and property or (c) business interruptions while damaged energy infrastructure is repaired or replaced, each of which could cause us to suffer substantial losses. InOur ~~response~~offshore operations may encounter additional marine perils, ~~over~~including ~~the~~hurricanes ~~last~~and ~~year~~other adverse weather conditions, El ~~Paso~~damage ~~announced~~from ~~certain~~collisions ~~actions~~with ~~designed~~vessels, toand ~~reduce~~governmental ~~its~~regulations. In ~~need~~addition, toalthough ~~access~~the potential effects of climate change on our operations (such ~~financial~~ ~~markets~~as hurricanes, ~~including~~flooding, ~~reductions~~etc.) are uncertain at this time, changes in ~~the~~climate ~~capital~~patterns ~~programs~~as a result of ~~certain~~global emissions of ~~its~~ ~~operating~~greenhouse ~~subsidiaries~~gas ~~and~~(GHG) could have a negative impact upon our operations in the ~~sale~~future, particularly with regard to any of ~~several~~our ~~non-core~~facilities ~~assets~~that are located in or near the Gulf of Mexico and other coastal regions.

IfWhile we ormaintain Elinsurance ~~Paso experience~~against ~~prolonged~~some ~~periods~~ of ~~recession~~these orrisks ~~slowed economic growth~~ in ~~the~~amounts ~~U.S., demand~~that ~~growth~~we ~~from~~believe ~~consumers~~are ~~for~~reasonable, ~~natural~~our ~~gas~~insurance ~~transported~~coverages byhave usmaterial ~~may~~deductibles, ~~continue~~self-insurance ~~to decrease~~levels, ~~which~~limits ~~could~~on ~~impact~~our ~~the~~maximum ~~development~~recovery ofand ~~our~~do ~~future~~not ~~expansion~~cover ~~projects~~all risks. ~~Additionally~~ For example, ~~our~~we ordo Elnot ~~Paso’s~~carry ~~access~~or toare ~~capital~~unable ~~could~~to beobtain ~~impeded~~insurance ~~and~~coverage ~~the~~on ~~cost of~~terms ~~capital~~that we ~~obtain~~find ~~could~~acceptable befor ~~higher.~~certain ~~Finally~~exposures including, webut ~~are~~not ~~subject~~limited to ~~the~~certain ~~risks arising~~environmental ~~from~~exposures ~~changes~~(including inpotential ~~legislation~~environmental fines and ~~regulation~~penalties), ~~associated~~business ~~with~~interruption, ~~such recession~~named orwindstorm/hurricane ~~prolonged~~exposures, ~~economic~~and ~~slowdown~~in limited circumstances, ~~including~~certain ~~creating~~political ~~preference~~risk exposures. The premiums and deductibles we pay for ~~renewables,~~ ascertain ~~part~~insurance ofpolicies aare ~~legislative~~also ~~package~~subject to ~~stimulate~~ the ~~economy.~~risk ~~Any~~ of ~~these~~ ~~events,~~substantial ~~which~~increases ~~are~~over ~~beyond~~time ~~our~~that ~~control,~~ could negatively impact our ~~business,~~ financial results. ofIn ~~operations~~addition, ~~financial~~we ~~condition~~may not be able to renew existing insurance policies or procure desirable insurance on commercially reasonable terms. There is also a risk that our insurers may default on their coverage obligations. As a result, ~~and liquidity~~we could be adversely affected if a significant event occurs that is not fully covered by insurance.

We are subject to ~~financing~~a complex set of laws and ~~interest~~regulations ~~rate~~that ~~risks~~regulate the energy industry for which we have to incur substantial compliance and remediation costs.

Our ~~future~~operations ~~success~~are subject to a complex set of federal, ~~financial~~ ~~condition~~state and ~~liquidity~~local ~~could~~laws beand ~~adversely~~regulations ~~affected~~that ~~based~~tend onto ~~our ability~~change from time to ~~access~~time ~~capital~~and generally are becoming increasingly more stringent. In addition to the laws and regulations affecting our business, there are various laws and regulations that regulate various market practices in the industry, including antitrust laws and laws that prohibit fraud and manipulation in the markets in which we operate. The authority of the Federal Trade Commission and ~~obtain~~the ~~financing~~FERC atto ~~cost~~impose ~~effective~~penalties ~~rates~~for violations of laws or regulation has generally increased over the last few years. ~~This~~ In addition, our business is ~~dependent~~subject onto alaws ~~number~~and regulations that govern environmental, health and safety matters. These regulations include compliance obligations for air emissions, water quality, wastewater discharge and solid and hazardous waste disposal, as well as regulations designed for the protection of ~~factors~~human health and safety and threatened or endangered species. Compliance obligations can result in significant costs to install and maintain pollution controls and to maintain measures to address personal and process safety and protection of the environment and animal habitat near our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed. In addition, we are exposed to ~~general~~fines ~~economic conditions~~and ~~discussed~~penalties ~~above~~to the extent that we fail to comply with the applicable laws and regulations, as well as the potential for limitations to be imposed on our operations. These regulations often impose remediation obligations associated with the investigation or clean-up of contaminated properties, as well as damage claims arising out of the contamination of properties or impact on natural resources. Finally, many of ~~which~~our assets are located and operate on federal, state, or local lands and are typically regulated by one or more federal, state or local agencies. For example, we ~~cannot~~operate ~~control~~assets that are located on federal lands located both onshore and offshore, ~~including~~which ~~changes in:~~are regulated by the Department of the Interior, particularly by the Bureau of Land Management and the Bureau of Ocean Energy Management, Regulation and Enforcement.

• our credit ratings;

• the structured and commercial financial markets;

• market perceptions of us or the natural gas and energy industry;

• tax rates due to new tax laws; and

• market prices for hydrocarbon products.

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The laws and regulations (and the interpretations thereof) that are applicable to our business could materially change in the future and increase the cost of our operations or otherwise negatively impact us.

The regulatory framework affecting our business is frequently subject to change, with the risk that either new laws and regulations may be enacted or existing laws and regulation may be amended. Such new or amended laws and regulations can materially affect our operations and our financial results. In this regard, there have been proposals to implement or amend federal, state, and local laws and regulations that could negatively impact our business, which includes among others:

•

Climate Change and other Emissions. There have been various legislative and regulatory proposals at the federal and state levels to address climate change and to regulate GHG emissions. The Environmental Protection Agency (EPA) and several state environmental agencies have already adopted regulations to regulate GHG emissions. Although natural gas as a fuel supply for power generation has the least GHG emissions of any fossil fuel, it is uncertain at this time what impact the existing and proposed regulations will have on the demand for natural gas and on our operations. This will largely depend on what regulations are ultimately adopted, including the level of any emission standards; the amount and costs of allowances, offsets and credits granted; and incentives and subsidies provided to other fossil fuels, nuclear power and renewable energy sources. Although the EPA has adopted a tailoring rule to regulate GHG emissions, it is not expected to materially impact our operations until 2016. However, the tailoring rule is subject to judicial reviews and such reviews could result in the EPA being required to regulate GHG emissions at lower levels that could subject us to regulation prior to 2016. There have also been various legislative and regulatory proposals at the federal and state levels to address various emissions from coal-fired power plants. Although such proposals will generally favor the use of natural gas fired power plants over coal-fired power plants, it remains uncertain what regulations will ultimately be adopted and when they will be adopted. Finally, there have been other various environmental regulatory proposals that could increase the cost of our environmental liabilities as well as increase our future compliance costs. For example, the EPA has proposed more stringent ozone standards, as well as implemented more stringent emission standards with regard to certain combustion engines on our pipeline system. It is uncertain what impact new environmental regulations might have on us until further definition is provided in the various legislative, regulatory and judicial branches. In addition, any regulations would likely increase our costs of compliance by requiring us to monitor emissions, install additional equipment to reduce carbon emissions and possibly to purchase emission credits, as well as potentially delay the receipt of permits and other regulatory approvals. While we may be able to include some or all of the costs associated with our environmental liabilities and environmental compliance in the rates charged by our pipeline and in the prices at which we sell natural gas, our ability to recover such costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final regulations and legislation.

•

Renewable / Conservation Legislation. There have been various legislative and regulatory proposals at the federal and state levels to provide incentives and subsidies to (a) shift more power generation to renewable energy sources and (b) support technological advances to drive less energy consumption. These incentives and subsidies could have a negative impact on natural gas consumption and thus have negative impacts on our operations and financial results.

•

Pipeline Safety. Various legislative and regulatory reforms associated with pipeline safety and integrity issues have been recently proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipeline and subjecting additional pipelines (including gathering and intrastate pipeline facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.

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We are exposed to the credit risk of our counterparties and our credit risk management may not be adequate to protect against such risk.

We are subject to the risk that our counterparties fail to make payments to us within the time required under our contracts. Our current largest exposure is associated with shippers under long-term transportation contracts on our pipeline system. Our credit procedures and policies may not be adequate to fully eliminate counterparty credit risk. In addition, in certain situations, we may assume certain additional credit risks for competitive reasons or otherwise. If our existing or future counterparties fail to pay and/or perform, we could be adversely affected. For example, we may not be able to effectively remarket capacity or enter into new contracts at similar terms during and after insolvency proceedings involving a customer.

We are exposed to the credit and performance risk of our key contractors and suppliers.

As an owner of energy infrastructure facilities with significant capital expenditures, we rely on contractors for certain construction and we rely on suppliers for key materials, supplies and services, including steel mills and pipe and tubular manufacturers. There is a risk that such contractors and suppliers may experience credit and performance issues that could adversely impact their ability to perform their contractual obligations with us, including their performance and warranty obligations. This could result in delays or defaults in performing such contractual obligations and increased costs to seek replacement contractors, each which could adversely impact us.

Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.

Our business requires the retention and recruitment of a skilled workforce including engineers, technical personnel and other professionals. We compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible, which have significant institutional knowledge that must be transferred to other employees. If we are unable to (a) retain our current employees, (b) successfully complete our knowledge transfer and/or (c) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

We have certain contingent liabilities that could exceed our estimates.

We have certain contingent liabilities associated with litigation and environmental matters. In this regard, although we have greatly reduced our litigation, regulatory and environmental exposures over the last several years, we continue to have contingent liabilities (see Part II, Item 8, Financial Statements and Supplementary Data, Note 8). Although we believe that we have established appropriate reserves for our litigation and environmental matters, we could be required to accrue additional amounts in the future and these amounts could be material.

We have also sold assets and either retained certain liabilities or indemnified certain purchasers against future liabilities related to assets sold, including liabilities associated with environmental and other representations that we have provided. Although we believe that we have established appropriate reserves for these liabilities, we could be required to accrue additional amounts in the future and these amounts could be material. We have experienced substantial reductions and turnover in the workforce that previously supported the ownership and operation of such assets which could result in difficulties in managing these retained liabilities, including a reduction in historical knowledge of the assets and business that is required to effectively manage these liabilities or defend any associated litigation or regulatory proceedings.

We are subject to interest rate risks.

Although a substantial portion of our debt capital structure has fixed interest rates, changes in market conditions, including potential increases in the deficits of foreign, federal and state governments, could have a negative impact on interest rates that could cause our financing costs to increase. Since interest rates are at historically low levels, it is anticipated that they will increase in the future.

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Risks Related to Our Affiliation with El Paso

El Paso files reports, proxy statements and other information with the SEC under the Securities Exchange Act of 1934, as amended. Each prospective investor should consider this information and the matters disclosed therein in addition to the matters described in this report. Such information is not included herein or incorporated by reference into this report.

We are an indirect wholly owned subsidiary of El Paso.

As an indirect wholly owned subsidiary of El Paso, subject to limitations in our credit agreements and indentures, El Paso has substantial control over:

• our payment of dividends; • decisions on our financing and capital raising activities; • mergers or other business combinations; • our acquisitions or dispositions of assets; and • our participation in El Paso’s cash management program.

• decisions on our financing and capital raising activities;

• mergers or other business combinations;

• our acquisitions or dispositions of assets; and

• our participation in El Paso’s cash management program.

El Paso may exercise such control in its interests and not necessarily in the interests of us or the holders of our long-term debt.

Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.

Due to our relationship with El Paso, adverse developments or announcements concerning El Paso or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Ba3 with a stable outlook by Moody’s Investor Service, BB- with a stable outlook by Standard & Poor’s and BB+ with a stable outlook by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB- rating by Fitch Ratings. Standard & Poor’s has assigned a below investment grade rating of BB to our senior unsecured indebtedness. ~~El Paso and its subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor Service and Fitch Ratings and (ii) on a negative outlook with Standard & Poor’s.~~ There is a risk that these credit ratings may be adversely affected in the future as the credit rating agencies ~~continue~~review totheir general credit requirements as well as review our and El Paso’s leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit ratings could impact our ability to access the capital markets, as well as our cost of capital ~~and collateral requirements~~.

El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated note receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated payables we have established. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position and cash flows. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 12.

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If El Paso is unable to renew its revolving credit facility that expires in November 2012, then it could negatively impact us.

We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however for our borrowings under the credit agreement, which were zero at December 31, 2010. El Paso’s credit agreement is due to expire November of 2012. Prior to maturity, El Paso plans to renew or extend this credit facility. The amount of credit capacity El Paso is able to obtain and the cost of such credit could have a negative impact on our liquidity position and financial results. In addition, the financial covenants set forth in any new facility may be more restrictive than the current facility and could reduce our financial and operating flexibility.

A default under El Paso’s $1.5 billion credit agreement by any party could accelerate our future borrowings, if any, under the credit agreement and our long-term debt, which could adversely affect our liquidity position.

Under the credit agreement, a default by El Paso, or any other borrower, could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

We may be subject to a change in control if an event of default occurs under El Paso’s credit agreement.

Under El Paso’s $1.5 billion credit agreement, our common stock and the common stock of one of El Paso’s other subsidiaries are pledged as collateral. As a result, our ownership is subject to change if there is a default under the credit agreement and El Paso’s lenders exercise rights over their collateral, even if we do not have any borrowings outstanding under the credit agreement. For additional information concerning El Paso’s credit facility, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

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We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2009. Under the credit agreement, a default by El Paso, or any other borrower, could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have not included a response to this item since no response is required under Item 1B of Form 10-K.

ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties, or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our material legal proceedings is included in Part II, Item 8, Financial Statements and Supplementary Data, Note 8, and is incorporated herein by reference.

ITEM 4. ~~SUBMISSION~~(REMOVED OFAND ~~MATTERS TO A VOTE OF SECURITY HOLDERS~~RESERVED)

Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of our common stock, par value $5 per share, is owned by an indirect subsidiary of El Paso and, accordingly, our stock is not publicly traded.

We pay dividends on our common stock from time to time from legally available funds that have been approved for payment by our Board of Directors. During 2010, we utilized $334 million of our note receivable from the cash management program to pay a dividend to our parent. No common stock dividends were declared or paid in 2009 or 2008.

ITEM 6. SELECTED FINANCIAL DATA

Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.

Overview

Our primary business consists of the interstate transportation and storage of natural gas. ~~Each~~ ofWe ~~these~~face ~~businesses faces~~ varying degrees of competition from other existing and proposed pipelines and LNG facilities, as well as from alternative energy sources used to generate electricity such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage services consist of the following types.

Type	~~Description~~	~~Percent of Total Revenues in 2009~~Description	Percent of 2010 Revenues
Reservation	Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.	61Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facilities. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.	68
Usage and Other	Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges and provide fuel in-kind based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	39Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) that pay usage charges and provide fuel in-kind based on the volume of gas actually transported, stored, injected or withdrawn. We also earn revenue from other miscellaneous sources.	32

The ~~Federal Energy Regulatory Commission (~~FERC) regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. Because of our regulated nature, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices, changes in supply and demand, changes in gas flows, regulatory actions, competition, declines in the creditworthiness of our customers and weather. We also experience volatility in our financial results when the amounts of natural gas used in our operations differ from the amounts we recover from our customers for that purpose.

We continue to manage the process of renewing expiring contracts to limit the risk of significant impacts on our revenues. Our ability to extend our existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and the market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs. However, we have entered into a substantial portion of firm transportation contracts at amounts that are less than these maximum allowable rates to remain competitive. ~~We refer to the difference between the maximum rates allowed under our tariff and the contractual rate we charge as discounts.~~

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~~Our~~In ~~existing contracts~~November ~~mature~~2010, atwe ~~various~~filed ~~times~~a ~~and~~rate incase ~~varying~~with ~~amounts~~the ofFERC ~~throughput~~proposing ~~capacity. The~~an ~~weighted~~increase ~~average~~in ~~remaining~~base ~~contract~~tariff ~~term~~rates, ~~for~~including a proposed change in our ~~active~~rate ~~contracts~~structure which is ~~approximately~~ ~~four~~expected ~~years~~to asincrease the percentage of ~~December~~reservation ~~31,~~revenues ~~2009. Below~~relative ~~are~~to ~~the contract~~revenues ~~expiration~~derived ~~portfolio~~from ~~and~~excess ~~the~~fuel ~~associated~~recoveries ~~revenue~~and ~~expirations~~throughput ~~for~~on our ~~firm~~ ~~transportation~~system. For ~~contracts~~a asfurther discussion of ~~December~~our ~~31,~~rate ~~2009~~case, ~~including~~see ~~those~~our ~~with terms~~Results ~~beginning~~of inOperations ~~2010~~discussion ~~or later~~below.

	Contracted Capacity		Percent of Total Contracted Capacity			Reservation Revenue		Percent of Total Reservation Revenue
	(BBtu/d)				(In millions)
2010		635		8		$	1		—
2011		603		8			30		6
2012		2,348		29			77		14
2013		1,392		17			121		23
2014		624		8			68		13
2015 and beyond		2,409		30			234		44
Total		8,011		100		$	531		100

Our existing contracts expire at various times and in varying amounts of throughput capacity. The weighted average remaining contract term for our active contracts is approximately four years as of December 31, 2010. Below are the contract expiration portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2010, including those with terms beginning in 2011 or later.

	Contracted Capacity			Percent of Contracted Capacity		Reservation Revenue		Percent of Reservation Revenue
	(BBtu/d)		(In millions)
2011		594			7	$	20		4
2012		2,607			33		106		19
2013		1,226			15		45		8
2014		735			9		30		6
2015		843			11		45		8
2016 and beyond		2,024			25		299		55
Total		8,029			100	$	545		100

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to investors to provide them with the same measure used by El Paso to evaluate our performance. and so that investors may evaluate our operating results without regard to our financing methods. We define EBIT as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. ~~We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods.~~ EBIT may not be comparable to measures used by other companies. Additionally, EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to ~~our~~ net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, ~~2009~~2010 compared with ~~2008~~2009.

Operating Results:

	2009			2008
	2010			2009
	(In millions,
	except for volumes)
Operating revenues	$	~~933~~845		$	~~907~~933
Operating expenses		(~~612~~577	)		(~~645~~612	)
Operating income		~~321~~268			~~262~~321
Earnings from unconsolidated affiliate		1114			1311
Other income, net		1323			1013
EBIT		~~345~~305			~~285~~345
Interest and debt expense		(~~155~~150	)		(~~136~~155	)
Affiliated interest income, net		1615			3316
Income tax expense		(7967	)		(7179	)
Net income	$	~~127~~103		$	~~111~~127
Throughput volumes (BBtu/d)		45,~~614~~081			4,~~864~~614

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EBIT Analysis:

	Revenue			Expense			Other			EBIT Impact
	Operating Revenue			Operating Expense			Other			Total
	Favorable/(Unfavorable)
	(In millions)
Gas not used in operations and other natural gas sales	$	19(82	)	$	1315		$	—		$	32(67	)
Expansions		7			(23	)		611			1115
Hurricanes		10			11			—			21
Reservation and other services revenues		(12	)		—			—			(12	)
Reservation and other services revenue		(12	)		—			—			(12	)
Operating and general and administrative expenses		—			15			—			15
Loss on long-lived assets		—			24			—			24
Hurricane repairs		—			7			—			7
Operating and general and administrative expenses		—			(7	)		—			(7	)
Other(1)		(1	)		1			2			2
Other(1)		2			(6	)		(5	)		(9	)
Total impact on EBIT	$	(88	)	$	35		$	13		$	(40	)
Total impact on EBIT	$	26		$	33		$	1		$	60

____________

(1) Consists of individually insignificant items.

Gas Not Used in Operations and Other Natural Gas Sales. The financial impact of ~~operational~~ gas, ~~net~~not ~~of gas~~ used in operations, is based on the amount of natural gas we are allowed to retain ~~and dispose of~~ according to our tariff, relative to the amounts of natural gas we use for ~~operating~~operations ~~purposes~~ and the price of natural gas. The financial impact of gas not used for operations is influenced by factors such as system throughput, changes in gas flows, facility enhancements and the ability to operate the system efficiently. Gas not used for operations results in revenues to us, which we recognize when the volumes are retained. ~~During~~For ~~2009,~~the ~~our~~year ~~EBIT~~ended ~~increased primarily~~December ~~due~~31, to2010 awhen ~~$19~~compared ~~million~~with ~~favorable~~2009, ~~impact~~our ~~resulting~~EBIT ~~from~~was ~~higher~~unfavorably ~~retained fuel~~impacted ~~volumes~~by inapproximately ~~excess~~$78 ofmillion ~~fuel~~due ~~used~~ to ~~operate~~lower ~~our~~realized ~~system~~prices and ~~higher~~lower ~~average realized~~volumes ~~prices~~of ongas ~~operational~~not ~~sales,~~used ~~partially~~in ~~offset~~operations byas a ~~lower~~result ~~index~~of ~~price used to value~~ the ~~volumes~~shift ~~that~~in weflow ~~retained~~patterns asand ~~compared~~unfavorable torevaluations ~~2008.~~of ~~Our~~retained ~~EBIT~~fuel ~~was also~~volumes, ~~favorably~~partially ~~impacted~~offset by $1315 million ~~due~~of to lower electric compression ~~utilization~~ usage.

Expansions. During 2010 and 2009, we benefited from increased reservation revenues due to expansion projects placed in service in 2009. These projects included the Carthage expansion project, the Concord Lateral expansion project, and the Blue Water expansion project. We capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on equity funds related to our construction of long-lived assets that is recorded as other income on our income statements. For the year ended December 31, 2010, we benefited from an increase in other income of approximately $11 million when compared to 2009, associated with the equity portion of AFUDC on our expansion projects, partially offset by depreciation and operating expenses of the new facilities.

~~Projects~~During ~~Placed in Service in 2009 and 2008. In November 2008~~2011, we ~~placed~~plan ~~the~~to ~~Blue~~spend ~~Water~~approximately ~~reconfiguration project~~$464 ~~into~~million ~~service.~~in Incapital ~~2009,~~on weour ~~placed~~backlog ~~several~~of expansion projects. Listed inbelow ~~service including~~is ~~the~~additional ~~Carthage~~information ~~expansion~~related into ~~May, the Concord Lateral expansion in October, and the Blue Water expansion in November. As a result,~~ our ~~revenues~~significant ~~and allowance~~backlog ~~for funds used during construction increased in 2009 as compared with 2008~~projects. ~~These increases were partially offset by depreciation and operating expenses of the new facilities.~~

~~Committed~~• ~~Projects~~300 ~~Not~~Line ~~Yet Completed~~Project. ~~The~~This ~~300 Line~~ expansion project involves the installation of ~~seven~~ eight looping segments in Pennsylvania and New Jersey totaling approximately 128 miles of ~~30-inch~~ pipeline, and the addition of approximately 5255,000 horsepower of compression following the installation of two new compressor stations and upgrades at seven existing compressor stations. Upon completion, we expect this project to increase natural gas delivery capacity in the region by approximately 350 MMcf/d. The ~~300~~expansion ~~Line Expansion~~ project will provide access to diversified natural gas supplies from the Gulf Coast, Appalachian, and Marcellus shale basin, and gas deliveries to points along the 300 Line path and into various interconnections with other pipelines in northern New Jersey, as well as an existing delivery point in White Plains, New York. ~~The~~All ~~expected~~of ~~cost~~the ~~for~~firm ~~this project~~transportation iscapacity ~~approximately~~resulting ~~$642~~from ~~million~~this ~~and~~project isin ~~anticipated~~the tonortheast ~~be placed in service November 2011~~U.S. Inmarket ~~July~~area ~~2009,~~is wefully ~~filed~~subscribed ~~an application~~ with ~~the~~one ~~FERC for~~shipper ~~certificate~~based ~~authorization~~on toa ~~construct and~~precedent weagreement ~~anticipate receiving~~which ~~their~~was ~~approval~~executed in the ~~first~~third quarter of ~~2010~~2009. ~~All~~During of2010, the ~~firm transportation~~FERC ~~capacity~~issued ~~resulting~~a favorable environmental assessment and we received certificate authorization from ~~this~~the ~~project~~FERC into construct the ~~northeast~~pipeline ~~U.S.~~and ~~market area~~compression isfacilities. ~~fully~~In ~~subscribed~~June ~~with~~2010, ~~one~~we ~~shipper~~commenced ~~based~~construction on aour ~~precedent~~compression ~~agreement~~facilities ~~which was~~related ~~executed~~to inthis ~~the~~project, ~~third~~with ~~quarter~~construction of ~~2009~~the remaining facilities to occur in 2011. An ~~environmental assessment~~The expected cost for this project is ~~expected~~approximately to$660 bemillion ~~issued~~and byis ~~the~~anticipated ~~FERC~~to inbe ~~the~~placed ~~first~~in ~~quarter~~service ~~of 2010~~November 2011.

~~Our~~• ~~system~~Northeast ~~is located~~Upgrade ~~over~~Project. aIn ~~significant~~2010, ~~portion~~we entered into precedent agreements with two shippers to provide 620 MMcf/d of additional firm transportation service from receipt points in the Marcellus shale basin ~~that~~to isan ~~under various~~interconnect ~~phases~~in ofNew ~~development by producers~~Jersey. WeAll ~~have~~of ~~executed~~the firm transportation ~~contracts~~ capacity is fully subscribed with these two shippers. ~~from~~This ~~the~~project ~~basin~~includes ~~utilizing~~approximately ~~existing~~40 ~~capacity.~~miles Weof ~~have~~pipeline ~~been in~~looping ~~discussions~~and ~~with~~approximately ~~producers~~22,310 tohorsepower ~~expand~~of ~~our~~additional ~~system~~compression. Additionally, we are placing appurtenances in service to provide ~~additional transportation~~interim ~~capacity~~backhaul ~~from~~transport of natural gas. The expected cost for this project is approximately $400 million, and the ~~Marcellus~~project ~~basin~~is anticipated to be placed in service in November 2013.

1417

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InReservation ~~February~~and Other Services Revenues. Throughput volumes on our system increased by 10 percent during 2010 compared to 2009. However, we ~~entered~~our ~~into~~reservation ~~precedent~~revenues ~~agreements~~were ~~with~~lower ~~two~~by ~~shippers~~approximately to$10 ~~provide~~million ~~620~~because ~~MMcf/d~~long-haul ~~of additional~~transports ~~firm~~have ~~transportation~~decreased ~~service~~due to a shift in receipts from ~~receipt~~the ~~points~~Gulf Coast region to the Rockies Express Pipeline interconnect in Ohio and the Marcellus shale basin, which is short-haul transportation and subject to lower rates. Offsetting these decreases was an ~~interconnect~~increase inof ~~New~~approximately ~~Jersey.~~$7 Inmillion ~~order~~in tocapacity ~~accommodate~~sales from the ~~additional~~ ~~service,~~Marcellus weshale ~~will~~basin ~~pursue~~in the Northeast ~~Upgrade~~market ~~project,~~area ~~which~~due ~~includes approximately~~to 37transportation ~~miles~~contracts ofwith 30shippers ~~inch~~which ~~pipeline~~were ~~looping~~executed ~~and~~in ~~the~~2009. We ~~addition~~believe ~~of approximately~~our ~~20,600~~Marcellus ~~horsepower~~expansion ofprojects ~~additional~~(300 ~~compression.~~Line ~~The~~Project ~~expected~~and ~~cost~~Northeast ~~for this~~Upgrade ~~project~~Project) iswill ~~approximately~~expand ~~$416~~our ~~million~~presence ~~and~~from ~~construction~~Marcellus isto ~~anticipated~~the toNew ~~be placed~~York inand ~~service~~New ~~November~~England ~~2013~~markets.

~~Hurricanes.~~For ~~During~~the ~~2008,~~year ~~we incurred~~ended ~~damage~~December to31, ~~sections~~2010, of our ~~Gulf~~overall ~~Coast~~EBIT ~~and~~was ~~offshore~~unfavorably ~~pipeline~~impacted ~~facilities due~~by to$6 ~~Hurricanes~~million ~~Gustav~~when ~~and~~compared ~~Ike.~~to In2009 ~~2008,~~due weto ~~recorded~~unfavorable ~~losses~~price ofspreads ~~$29~~on ~~million related~~our tointerruptible ~~gas~~services. Also ~~loss~~unfavorably ~~from~~impacting ~~various~~our ~~damaged~~EBIT ~~facilities,~~was ~~lower~~an ~~volume~~adjustment of ~~gas~~$6 ~~not used~~million into ~~operations,~~defer ~~lower usage~~ revenue, ~~and~~on ~~repair~~certain ~~costs~~of ~~that~~our ~~were~~negotiated ~~not recoverable~~rate ~~from~~contracts ~~insurance due~~ to ~~losses~~future ~~not~~periods. Offsetting ~~exceeding~~these ~~self-retention~~unfavorable ~~levels.~~impacts ~~In 2009,~~was wean ~~recorded~~increase ~~losses~~ of $85 million ~~for~~in ~~repair~~liquids, ~~costs~~separation ~~that~~and ~~were~~dehydration ~~not recoverable~~sales ~~from~~due ~~insurance. We continue~~ to ~~evaluate~~higher ~~those~~contractual ~~damaged~~rates ~~facilities~~ for ~~further~~ ~~repair~~the oryear ~~retirement.~~ended ~~See~~December ~~Liquidity~~31, ~~and~~2010 ~~Capital Resources~~compared ~~for~~to ~~a further discussion of the hurricanes~~2009.

~~Reservation~~If ~~and~~we ~~Other~~determine ~~Services Revenues.~~there ~~During~~is ~~2009~~a sufficient change in our revenues, costs or billing determinants, we have the option to file a rate case with the FERC to provide an opportunity to recover our ~~EBIT~~prudently ~~was~~incurred ~~unfavorably~~costs. In ~~impacted~~November by2010, we filed a ~~decrease~~rate ~~of $10~~case ~~million~~with the FERC proposing an increase in ~~usage~~base tariff rates, including a proposed change in our rate structure which is expected to increase the percentage of reservation revenues ~~due~~relative to ~~decreased~~revenues ~~activity~~derived ~~under~~from ~~various interruptible~~excess ~~services~~fuel ~~provided~~recoveries ~~under~~and throughput on our system. These new base tariff ~~and~~rates awould ~~decrease~~increase ofrevenue by approximately $10203 million ~~due~~annually toover ~~increasing~~previously ~~competition~~effective intariff rates. In December 2010, the ~~southeast~~FERC ~~area~~issued an order accepting and ~~milder weather.~~suspending ~~Partially~~the ~~offsetting~~effective ~~these~~date ~~decreases~~of ~~was~~the anproposed ~~increase~~rates to June 1, 2011, subject to refund, the outcome of ~~approximately $8~~a ~~million~~hearing inand ~~capacity~~other ~~sales~~proceedings. ~~primarily~~At ~~from~~this time, the ~~Marcellus~~outcome ~~shale~~of ~~basin~~this inmatter ~~the northeast~~is ~~market~~not ~~area~~currently ~~due~~determinable. Although this rate case is intended to ~~transportation~~address ~~contracts~~significant ~~with~~factors ~~shippers~~leading ~~which~~to ~~were executed~~the ~~during~~loss ~~2009~~in revenues or increased costs, it will not eliminate all ongoing business risks including competition and shifts in throughput.

~~During~~Operating ~~2009,~~and ~~our throughput~~General ~~volumes decreased compared with 2008. This was due, in part, to general weakness in natural gas demand in the U.S., including general reductions in industrial~~ and ~~power~~Administrative ~~generation loads in the northeast~~Expenses. The demand for gas from the power generation sector was negatively impacted by economic factors but positively impacted by the displacement of coal-fired generation by gas-fired generation. Although fluctuations in throughput on our system have a limited impact on our short-term financial results because the ~~majority~~For ~~of our revenues are derived from firm reservation charges, it can be an indication of~~ the ~~risks~~year weended ~~may~~December ~~face when seeking to recontract or renew any of our existing firm transportation contracts in the future. Continuing negative economic impacts on demand~~31, ~~as well as adverse shifting of sources of supply~~2010, ~~could negatively~~our ~~impact~~operating ~~basis~~and ~~differentials~~general and ~~our~~administrative ~~ability~~expenses towere ~~renew~~lower ~~firm transportation~~than ~~contracts~~2009 ~~that~~primarily ~~are~~due ~~expiring on our system or our ability~~ to ~~renew such~~lower ~~contracts~~payroll ~~at current rates. If we determine there is a significant change in our~~ costs ~~or billing determinants~~, wenet ~~will~~of ~~have~~capitalization ~~the~~and ~~option~~reimbursement tofrom ~~file a rate case with the FERC to recover our prudently incurred costs~~affiliates.

~~Loss~~Hurricane ~~on Long-Lived Assets~~Repairs. ~~During~~ Our ~~2008,~~EBIT wewas ~~recorded~~unfavorably ~~impairments~~impacted ofby $257 million, ~~including~~in an2009 ~~impairment related~~due to ~~our~~repair ~~Essex-Middlesex~~costs ~~Lateral~~that ~~project~~were not recoverable from insurance due to ~~its~~losses ~~prolonged~~which ~~permitted process~~did not exceed our self-retention levels.

~~Operating~~Other and General and Administrative Expenses. During 2009, our operating and general and administrative expenses were increased primarily due to higher benefits and pension costs of approximately $21 million, partially offset by a reduction of $13 million in pipeline maintenance costs.Matter

We entered into an agreement with an effective date of October 2010 to sell certain of our offshore pipeline assets and related facilities. We have filed an abandonment application with the FERC related to the sale. The sale is contingent upon receiving FERC approval of the abandonment application including the ability to recover in our future rates the difference between the regulatory net book value and the purchase price as well as the designation of certain facilities as non-jurisdictional. If approved, we expect to complete the sale of these assets by mid-2012 and we may incur a loss on the sale for financial accounting purposes. However, the outcome of FERC's approval of our application is currently undeterminable. As such, we have not considered the assets as held for sale.

Interest and Debt Expense

Interest and debt expense for the year ended December 31, ~~2009~~2010, was $195 million ~~higher~~lower than in ~~2008~~ 2009 primarily due to ~~the~~a ~~issuance~~lower ofoutstanding ~~$250~~balance ~~million~~on ofour ~~8.00%~~polychlorinated ~~senior~~biphenyls ~~notes~~(PCB) ~~in January~~refund ~~2009~~obligations.

~~Affiliated Interest Income, Net~~18

Affiliated interest income, net for the year ended December 31, 2009, was $17 million lower than in 2008 primarily due to lower average short-term interest rates on advances to El Paso under its cash management program, partially offset by higher average advances. The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:

	2009			2008
	(In millions, except for rates)
Average advance due from El Paso	$	931		$	768
Average short-term interest rate		1.7	%		4.4	%

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Affiliated Interest Income, Net

The following table shows the average advances due from El Paso and the average short-term interest rates for the year ended December 31:

	2010			2009
	(In millions, except for rates)
Average advance due from El Paso	$	1,015		$	931
Average short-term interest rate		1.5	%		1.7	%

Income Taxes

Our effective tax rate of 3839 percent and 3938 percent for the years ended December 31, ~~2009~~2010 and ~~2008~~ 2009 was higher than the statutory rate of 35 percent due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 3.

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Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program. At December 31, ~~2009~~2010, we had ~~notes~~a note receivable from El Paso of approximately $1.0 billion of which approximately $930.4 ~~million~~billion was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. During ~~At December 31~~2010, ~~2009,~~ we ~~had~~utilized ~~a non-interest~~$334 ~~bearing~~million ~~note receivable~~ of ~~$334~~our ~~million~~note receivable from an El Paso affiliate~~. This~~ ~~note~~to ispay ~~reflected as~~ a ~~reduction~~dividend ofto our ~~stockholder’s equity based on uncertainties regarding the timing and method through which El Paso will settle these balances~~parent. See Item 8, Financial Statements and Supplementary Data, Note 12 for a further discussion of El Paso’s cash management program ~~and our other affiliate note receivable~~. Our primary uses of cash are for working capital, ~~and~~ capital expenditures and debt service requirements. For the year ended December 31, 2010 compared with 2009, our operating cash flows decreased by approximately $120 million primarily due to lower revenues, payment of income taxes and settlement of refund obligations associated with our PCB liability. Our cash capital expenditures for the year ended December 31, ~~2009~~2010 and those planned for ~~2010~~2011 are listed below.

	2009		Expected 2010
	2010		Expected 2011
	(In millions)
Maintenance	$	139	$	159
Maintenance(1)	$	94	$	172
Expansions		~~128~~132		~~179~~464
Hurricanes		30		35
Other(2)		95		101
Other(1)		64		97
Total	$	321	$	737
Total	$	361	$	470

____________

(1) Amount ~~Relates~~is tonet ~~building~~of ~~renovations~~insurance atproceeds ~~our corporate facilities~~received.

~~Our~~(2) Relates ~~expected 2010 expansion capital expenditures primarily relate~~ to ~~our~~building ~~300~~renovations ~~Line~~at ~~expansion project. Our maintenance capital expenditures primarily relate to maintaining and improving the integrity of~~ our ~~pipeline,~~corporate ~~complying with regulations and ensuring the safe and reliable delivery of natural gas to our customers. In addition, we continue to evaluate our damaged~~ facilities ~~caused by hurricanes Ike and Gustav for further repair or retirement~~.

~~Although~~Our ~~recent financial~~expected ~~market~~2011 ~~conditions~~maintenance ~~have~~capital ~~shown~~expenditures ~~signs~~primarily ofrelate ~~improvement,~~to ~~continued volatility~~maintaining ~~in 2010~~ and ~~beyond~~improving in the ~~financial~~integrity ~~markets~~of ~~could impact~~ our ~~longer-term~~ ~~access~~pipeline, tocomplying ~~capital~~with ~~for~~regulations ~~future~~and ~~growth~~ensuring ~~projects as well as~~ the ~~cost~~safe ~~of such~~and ~~capital.~~reliable ~~Additionally,~~delivery ~~although the impacts are difficult to quantify at this point, a prolonged recovery~~ of ~~the global economy could have adverse impacts on~~ natural gas ~~consumption~~to ~~and~~our ~~demand~~customers. ~~However,~~Also weincluded ~~believe~~in our ~~exposure to~~maintenance ~~changes~~capital inexpenditures ~~natural~~are amounts ~~gas~~related ~~consumption~~to ~~and~~damage ~~demand~~repairs isfor ~~largely~~hurricanes ~~mitigated by a revenue base~~ that isoccurred ~~mostly~~in ~~comprised~~2005 ~~of long-term contracts that are based on firm demand charges~~ and ~~are~~2008. Our ~~less~~expected ~~affected~~expansion bycapital aexpenditures ~~potential~~primarily ~~reduction~~relate into ~~the~~our ~~actual usage~~300 orLine ~~consumption of natural gas~~Project.

WeAlthough ~~believe~~financial wemarket conditions have ~~adequate~~ ~~liquidity~~improved, ~~available~~continued tovolatility usin tothe ~~meet~~financial ~~our~~markets ~~capital~~could ~~requirements~~impact ~~and~~ our ~~existing~~ ~~operating~~longer-term ~~needs~~access ~~through~~to ~~cash~~capital ~~flows~~for ~~from~~future ~~operating~~growth ~~activities~~projects ~~and amounts~~as ~~available~~well toas usthe ~~under~~cost Elof ~~Paso’s~~such ~~cash management program~~capital. ~~As of December 31~~Additionally, ~~2009,~~although Elthe ~~Paso~~impacts ~~had~~are ~~approximately~~difficult ~~$1.8~~to ~~billion~~quantify ofat ~~available~~this ~~liquidity~~point, ~~including~~ ~~approximately~~a ~~$1.3~~prolonged ~~billion~~recovery of ~~capacity available to it under various committed credit facilities. In addition to~~ the ~~cash~~global ~~management~~economy ~~program~~could ~~above, we~~have ~~are~~adverse ~~eligible~~impacts toon ~~borrow~~natural ~~amounts~~gas ~~available~~consumption ~~under El Paso’s $1.5 billion credit agreement~~ and ~~are only liable for amounts we directly borrow~~demand. ~~As of December 31~~However, ~~2009,~~ Elwe ~~Paso~~believe ~~had~~our ~~approximately~~exposure ~~$0.8~~to ~~billion~~changes ofin ~~capacity~~natural ~~remaining~~gas ~~and~~consumption ~~available to us~~ and ~~our~~demand ~~affiliates~~is ~~under~~partially ~~this~~mitigated ~~credit~~by ~~agreement,~~a ~~and~~revenue ~~none~~base ofthat ~~the~~includes ~~amount outstanding~~long-term ~~under~~contracts ~~the~~that ~~facility~~are ~~was~~based ~~issued~~on orfirm ~~borrowed~~demand ~~by us~~charges. In ~~While~~November 2010, we dofiled ~~not anticipate~~ a ~~need~~rate tocase ~~directly~~with ~~access~~ the ~~financial~~FERC ~~markets~~proposing, inamong ~~2010~~other ~~for~~things, ~~any~~a ~~of our~~change ~~operating~~in ~~activities~~our orrate ~~expansion~~structure. For ~~capital~~a ~~needs~~further ~~based~~discussion onof ~~liquidity~~our ~~available to~~rate uscase, ~~market~~see ~~conditions~~our ~~may~~Results ~~impact~~of ~~our~~Operations ~~ability~~discussion ~~to act opportunistically~~above.

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2010, El Paso had approximately $0.9 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. While we do not anticipate a need to directly access the financial markets in 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.

For further detail on our risk factors including potential adverse general economic conditions including our ability to access financial markets which could impact our operations and liquidity, see Part I, Item 1A, Risk Factors.

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Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Item 8, Financial Statements and Supplementary Data, Note 8, which is incorporated herein by reference.

Climate Change and Energy Legislation and Regulation . There are various legislative and regulatory measures relating to climate change and energy policies that have been proposed and, if enacted, will likely impact our business.20

Climate Change Legislation and Regulation. Measures to address climate change and greenhouse gas (GHG) emissions are in various phases of discussions or implementation at international, federal, regional and state levels. Over 50 countries, including the U.S. have submitted formal pledges to cut or limit their emissions in response to the United Nations-sponsored Copenhagen Accord. It is reasonably likely that federal legislation requiring GHG controls will be enacted within the next few years in the United States. Although it is uncertain what legislation will ultimately be enacted, it is our belief that cap-and-trade or other market-based legislation that sets a price on carbon emissions will increase demand for natural gas, particularly in the power sector. We believe this increased demand will occur due to substantially less carbon emissions associated with the use of natural gas compared with alternate fuel sources for power generation, including coal and oil-fired power generation. However, the actual impact on demand will depend on the legislative provisions that are ultimately adopted, including the level of emission caps, allowances granted, offset programs established, cost of emission credits and incentives provided to other fossil fuels and lower carbon technologies like nuclear, carbon capture sequestration and renewable energy sources.

It is also reasonably likely that any federal legislation enacted would increase our cost of environmental compliance by requiring us to install additional equipment to reduce carbon emissions from our larger facilities as well as to potentially purchase emission allowances. Based on 2008 operational data we reported to the California Climate Action Registry (CCAR), our operations in the United States emitted approximately 4.7 million tonnes of carbon dioxide equivalent emissions during 2008. We believe that approximately 4.1 million tonnes of the GHG emissions that we reported to CCAR would be subject to regulations under the climate change legislation that passed in the U.S. House of Representatives (the House) in June 2009. Of these amounts that would be subject to regulation, we believe that approximately one-third would be subject to the cap-and-trade rules contained in the proposed legislation and the remainder would be subject to performance standards. As proposed by the House, the portion of our GHG emissions that would be subject to cap-and-trade rules could require us to purchase allowances or offset credits and the portion of our GHG emissions that would be subject to performance standards could require us to install additional equipment or initiate new work practice standards to reduce emission levels at many of our facilities. The costs of purchasing emission allowances or offset credits and installing additional equipment or changing work practices would likely be material. Increases in costs of our suppliers to comply with such cap-and-trade rules and performance standards, such as the electricity we purchase in our operations, could also be material and would likely increase our cost of operations. Although we believe that many of these costs should be recoverable in the rates we charge our customers, recovery is still uncertain at this time. A climate change bill was also voted upon favorably by the Senate Committee on Energy and Public Works (the Committee) in November 2009 and has been ordered to be reported out of the Committee. Any final bill passed out of the U.S. Senate will likely see further substantial changes and we cannot yet predict the form it may take, the timing of when any legislation will be enacted or implemented or how it may impact our operations if ultimately enacted.

The Environmental Protection Agency (EPA) finalized regulations to monitor and report GHG emissions on an annual basis. The EPA also proposed new regulations to regulate GHGs under the Clean Air Act, which the EPA has indicated could be finalized as early as March 2010. The effective date and substantive requirements of any EPA final rule is subject to interpretation and possible legal challenges. In addition, it is uncertain whether federal legislation might be enacted that either delays the implementation of any climate change regulations of the EPA or adopts a different statutory structure for regulating GHGs than is provided for pursuant to the Clean Air Act. Therefore, the potential impact on our operations and construction projects remains uncertain.

In addition, in March 2009, the EPA proposed a rule impacting emissions from reciprocating internal combustion engines, which would require us to install emission controls on our pipeline system. It is expected that the rule will be finalized in August 2010. As proposed, engines subject to the regulations would have to be in compliance by August 2013. Based upon that timeframe, we would expect that we would commence incurring expenditures in late 2010, with the majority of the work and expenditures incurred in 2011 and 2012. If the regulations are adopted as proposed, we would expect to incur approximately $22 million in capital expenditures over the period from 2010 to 2013.

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Legislative and regulatory efforts are underway in various states and regions. These rules once finalized may impose additional costs on our operations and permitting our facilities, which could include costs to purchase offset credits or emission allowances, to retrofit or install equipment or to change existing work practice standards. In addition, various lawsuits have been filed seeking to force further regulation of GHG emissions, as well as to require specific companies to reduce GHG emissions from their operations. Enactment of additional regulations by the federal or state governments, as well as lawsuits, could result in delays and have negative impacts on our ability to obtain permits and other regulatory approvals with regard to existing and new facilities, could impact our costs of operations, as well as require us to install new equipment to control emissions from our facilities, the costs of which would likely be material.

Energy Legislation. In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint”. These proposals would establish renewable energy and efficiency standards at both the federal and state level, some of which would require a material increase of renewable sources, such as wind and solar power generation, over the next several decades. There have also been proposals to increase the development of nuclear power and commercialize carbon capture and sequestration especially at coal-fired facilities. Other proposals would establish incentives for energy efficiency and conservation. Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas. However, such proposals if enacted could negatively impact natural gas demand over the longer term.

New Accounting Pronouncements Issued But Not Yet Adopted

See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to the risk of changing interest rates. At December 31, ~~2009~~2010, we had an interest bearing ~~notes~~note receivable from El Paso of approximately $1.0 billion, with a variable interest rate of 1.5% that ~~are~~is due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of ~~these~~this ~~notes~~note receivable approximates the carrying value due to the ~~notes~~ note being due on demand and the market-based nature of the interest rate.

The table below shows the carrying value, the related weighted-average effective interest rates on our non-affiliated fixed rate long-term debt securities and the estimated fair value of these securities ~~estimated~~ based on quoted market prices for the same or similar issues.

December 31, 2009

December 31, 2008

December 31, 2010

December 31, 2009

Expected Fiscal Year of Maturity of Carrying Amounts

2011

~~2014~~2016 and Thereafter

Total

Fair Value

Carrying Amount

Fair Value

(In millions, except for rates)

Liabilities:

Long-term debt— fixed rate

8385

1,~~763~~766

1,~~846~~851

2,~~086~~071

1,~~605~~846

12,~~311~~086

Average effective interest rate

78.50

7.8

We are also exposed to risks associated with changes in natural gas prices on natural gas that we are allowed to retain, net of gas used in operations. Retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. We are at risk if we retain less natural gas than needed for these purposes. Pricing volatility may also impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments. We sell retained gas in excess of gas used in operations when such gas is not operationally necessary or when such gas needs to be removed from the system, which may subject us to both commodity price and locational price differences depending on when and where that gas is sold. In some cases, where we have made a determination that, by a certain point in time, it is operationally necessary to dispose of gas not used in operations, we use forward sales contracts, which include fixed price and variable price contracts within certain price constraints, to manage this risk. In December 2009, we entered into a contract with our affiliate, El Paso Marketing, L.P., to sell up to 22 TBtu of natural gas not used in our operations in 2011 at a price of $6.48 per MMBtu. In November 2010, we filed a rate case with the FERC proposing, among other things, a change in our rate structure which is expected to increase the percentage of reservation revenues relative to revenues derived from excess fuel recoveries and throughput on our system. For a further discussion of our rate case, see Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by the Securities and Exchange Commission (SEC) rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

• ~~Pertain~~pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

• ~~Provide~~provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

• ~~Provide~~provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, ~~2009~~2010. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, ~~2009~~ 2010.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of Tennessee Gas Pipeline Company

We have audited the accompanying consolidated balance sheets of Tennessee Gas Pipeline Company (the Company) as of December 31, ~~2009~~2010 and ~~2008~~2009, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the three years in the period ended December 31, ~~2009~~2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the three years in the period ended December 31, ~~2009~~2010. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tennessee Gas Pipeline Company at December 31, ~~2009~~2010 and ~~2008~~2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2009~~2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Notes 3 and 1 to the consolidated financial statements, effective January 1, 2007, the Company adopted a new income tax accounting standard, and effective January 1, 2008, the Company adopted the provisions of an accounting standard update related to the measurement date and changed the measurement date of its postretirement benefit plan.

/s/ Ernst & Young LLP

Houston, Texas

~~March~~February 128, ~~2010~~ 2011

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In millions)

	Year Ended December 31,
	2009			2008			2007
	2010			2009			2008
Operating revenues	$	~~933~~845		$	~~907~~933		$	~~862~~907
Operating expenses
Operation and maintenance		~~370~~328			~~386~~370			~~338~~386
Depreciation and amortization		~~187~~196			~~182~~187			~~170~~182
Loss on long-lived assets		1—			251			—25
Taxes, other than income taxes		5453			5254			5652
		612			645			564
		577			612			645
Operating income		~~321~~268			~~262~~321			~~298~~262
Earnings from unconsolidated affiliate		1114			1311			13
Other income, net		1323			1013			1910
Interest and debt expense		(~~155~~150	)		(~~136~~155	)		(~~130~~136	)
Affiliated interest income, net		1615			3316			4433
Income before income taxes		~~206~~170			~~182~~206			~~244~~182
Income tax expense		7967			7179			9171
Net income	$	~~127~~103		$	~~111~~127		$	~~153~~111

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

	December 31,
	2009			2008
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	—		$	—
Accounts and notes receivable
Accounts and note receivable
Customer		1224			2412
Affiliates		~~152~~378			81152
Other		1351			13
Materials and supplies		4344			4143
Deferred income taxes		4443			844
Other		85			108
Total current assets		~~272~~545			~~177~~272
Property, plant and equipment, at cost		4,~~680~~951			4,~~365~~680
Less accumulated depreciation and amortization		~~936~~1,056			~~884~~936
		3,744			3,481
		3,895			3,744
Additional acquisition cost assigned to utility plant, net		1,~~963~~923			21,~~002~~963
Total property, plant and equipment, net		5,~~707~~818			5,~~483~~707
Other assets
Notes receivable from affiliate		939			800
Note receivable from affiliate		617			939
Investment in unconsolidated affiliate		7956			8179
Other		7076			5370
		1,088			934
		749			1,088
Total assets	$	7,~~067~~112		$	67,~~594~~067
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	6090		$	5460
Affiliates		7238			3672
Other		4757			5247
Taxes payable		94			82
Current maturities of long-term debt		86			—
Contractual deposits		31			60
Taxes payable		23			94
Asset retirement obligations		66			5
Contractual deposits		28			31
Accrued interest		33			24
Asset retirement obligations		28			66
Regulatory liabilities		28			3
Accrued interest		33			33
Other		24			23
Regulatory liabilities		78			28
Total current liabilities		455			339
Other		38			24
Long-term debt		1,846			1,605
Total current liabilities		499			455
Long-term debt, less current maturities		1,765			1,846
Other liabilities
Deferred income taxes		1,~~351~~422			1,~~314~~351
Regulatory liabilities		~~153~~90			~~191~~153
Other		6435			7464
		1,568			1,579
		1,547			1,568
Commitments and contingencies (Note 8)
Stockholder’s equity
Common stock, par value $5 per share; 300 shares authorized; 208 shares issued and outstanding		—			—
Additional paid-in capital		2,209			2,209
Retained earnings		1,~~323~~092			1,~~196~~323
Note receivable from affiliate		~~(334~~—	)		(334	)
Total stockholder’s equity		3,~~198~~301			3,~~071~~198
Total liabilities and stockholder’s equity	$	7,~~067~~112		$	67,~~594~~067

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

	Year Ended December 31,
	2009			2008			2007
	2010			2009			2008
Cash flows from operating activities
Net income	$	~~127~~103		$	~~111~~127		$	~~153~~111
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		~~187~~196			~~182~~187			~~170~~182
Deferred income tax expense		272			142			8814
Earnings from unconsolidated affiliate, adjusted for cash distributions		28			32			143
Loss on long-lived assets		1—			251			—25
Other non-cash income items		(216	)		(42	)		(104	)
Asset and liability changes
Accounts receivable		1742			1917			1519
Accounts payable		36			10			(15	)
Change in deferred purchase price from accounts receivable sales		(35	)		—			—
Taxes payable		17			45			(40	)
Accounts payable		(41	)		36			10
Other current assets		(1	)		(5	)		(6	)
Taxes payable		(73	)		17			45
Other current liabilities		16			(16	)		(4	)
Other current assets		(3	)		(1	)		(5	)
Non-current assets		(24	)		—			(13	)
Other current liabilities		16			16			(16	)
Non-current liabilities		(10	)		21			(66	)
Non-current assets		(14	)		(24	)		—
Net cash provided by operating activities		368			405			286
Non-current liabilities		(3	)		(10	)		21
Net cash provided by operating activities		252			368			405
Cash flows from investing activities
Capital expenditures		(~~361~~321	)		(~~323~~361	)		(~~364~~323	)
Net change in notes receivable from affiliates		~~(232~~390	)		(~~100~~232	)		39(100	)
Proceeds from the sale of asset		—			—			35
Return of capital from investment in unconsolidated affiliate		15			—			—
Other		(92	)		18(9	)		418
Net cash used in investing activities		(602	)		(405	)		(286	)
Net cash provided by (used in) investing activities		82			(602	)		(405	)
Cash flows from financing activities
Net proceeds from the issuance of long-term debt		~~234~~—			—234			—
Other		—			—			—
Dividend paid to parent		(334	)		—			—
Net cash provided by financing activities		234			—			—
Net cash provided by (used in) financing activities		(334	)		234			—
Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—
End of period	$	—		$	—		$	—
Supplemental cash flow information
Interest paid, net of amounts capitalized	$	133		$	130		$	120
Income tax payments		78			60			12

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except share amounts)

	Common Stock				Additional Paid-in		Retained			Note Receivable from			~~Accumulated~~Total ~~Other Comprehensive~~Stockholder’s			~~Total Stockholder’s~~
	Shares		Amount		Capital		Earnings			Affiliate			~~Income~~Equity			~~Equity~~
January 1, 2007		208	$	—	$	2,207	$	947		$	—		$	3		$	3,157
January 1, 2008		208	$	—	$	2,209	$	1,085		$	—		$	3,294
Net income								~~153~~111						111			~~153~~
Adoption of new income tax accounting standard, net of income taxes of $(8) (Note 3)								(15	)								(15	)
Reclassification of note receivable from affiliate (Note 12)				—							(334	)		(334	)
Reclassification to regulatory liability (Note 9)														(3	)		(3	)
December 31, 2008		208		—		2,209		1,196			(334	)		3,071
Other						2											2
Net income								127						127
December 31, 2007		208		—		2,209		1,085			—			—			3,294
December 31, 2009		208		—		2,209		1,323			(334	)		3,198
Net income								~~111~~103						103			~~111~~
Reclassification of note receivable from affiliate (Note 12)											(334	)		334			~~(334~~	)
December 31, 2008		208		—		2,209		1,196			(334	)		—			3,071
Dividend paid to parent								(334	)					(334	)
Net income								127									127
December 31, 2010		208	$	—	$	2,209	$	1,092		$	—		$	3,301
December 31, 2009		208	$	—	$	2,209	$	1,323		$	(334	)	$	—		$	3,198

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware corporation incorporated in 1947, and an indirect wholly owned subsidiary of El Paso Corporation (El Paso). Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of intercompany accounts and transactions.

We consolidate entities when we ~~either (i)~~ have the ability to control or direct the operating and financial decisions ~~and policies~~ of ~~that~~the entity or ~~(ii)~~when ~~are~~we ~~allocated~~have a ~~majority of~~significant interest in the entity’s ~~losses~~that ~~and/or~~gives ~~returns~~us ~~through~~the ~~our~~ability ~~interests~~to indirect the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an ~~entity~~ ~~and whether we are allocated a majority of the~~ entity’s ~~losses and/or returns~~ involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, or direct the policies ~~and~~, decisions ofor anactivities ~~entity and where we are not allocated a majority~~ of ~~the entity’s~~an ~~losses and/or returns~~entity. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can, and often do, differ from those estimates.

Regulated Operations

Our natural gas pipeline and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) ~~under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978~~ and ~~the Energy Policy Act of 2005. We~~ follow the Financial Accounting Standards Board’s (FASB) accounting standards for regulated operations. Under these standards, we record regulatory assets and liabilities that would not be recorded ~~under GAAP~~ for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that are expected to be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, loss on reacquired debt, taxes related to an equity return component on regulated capital projects and certain costs related to gas not used in operations and other costs included in, or expected to be included in, future rates.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than three months to be cash equivalents.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural gas imbalances due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. We regularly review collectability and establish or adjust our allowance as necessary using the specific identification method.

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Materials and Supplies

We value materials and supplies at the lower of cost or market value with cost determined using the average cost method.

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Natural Gas Imbalances

Natural gas imbalances occur when the amount of natural gas delivered from or received by a the pipeline ~~system or storage facility~~ differs from the contractual amount to be delivered or received. We value these imbalances due to or from shippers and operators utilizing current index prices. Imbalances are settled ineither as cash outs or in-kind, subject to the terms of our tariff.

Imbalances due from others are reported in our balance sheet as either accounts receivable from customers or accounts receivable from affiliates. Imbalances owed to others are reported on the balance sheet as either ~~trade~~ accounts payable or accounts payable to affiliates. We classify all imbalances as current as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that first placed the asset in service. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items.

We use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the ~~FERC-accepted~~ depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. ~~Currently,~~ ~~our depreciation rates vary from one percent to 25 percent per year. Using these rates, the remaining depreciable lives of these assets range from one to 51 years.~~ We re-evaluate depreciation rates each time we file with the FERC for aan ~~change~~increase or decrease in our transportation and storage rates. Currently, our depreciation rates vary from one percent to 25 percent per year.

When we retire regulated property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We do not recognize a gain or loss unless we sell an entire operating unit, as defined by the FERC. We include gains or losses on dispositions of operating units in operation and maintenance expense in our income statements. For properties not subject to regulation by the FERC, we reduce property, plant and equipment for its original cost, less accumulated depreciation and salvage value with any remaining gain or loss recorded in income.

Included in our property balances are additional acquisition costs ~~assigned to utility plant~~, which represent the excess ~~of allocated~~ purchase costs ~~over~~associated ~~the~~with ~~historical~~purchase ~~costs of~~business ~~the~~combinations ~~facilities.~~allocated to us. These costs are amortized on a straight-line basis ~~over 62 years using the same rates as the related assets,~~ and weare do not ~~recover~~recoverable ~~these excess costs~~ in our rates under current FERC policies.

At We ~~December~~capitalize ~~31, 2009~~a carrying cost (an allowance for funds used during construction or AFUDC) on debt and ~~2008,~~equity wefunds ~~had~~related ~~$271~~to ~~million~~the construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and ~~$207~~a ~~million~~return on the investment financed by equity. The debt portion is calculated based on the average cost of ~~construction~~debt. ~~work~~Interest ~~in progress~~costs capitalized are included inas ~~our~~a ~~property,~~reduction ~~plant~~to interest and ~~equipment~~debt expense on our income statement. The equity portion is calculated based on the most recent FERC approved rate of return. Equity amounts capitalized are included in other income on our income statements.

WeAsset ~~capitalize a carrying cost (an allowance for funds used during construction) on debt~~ and ~~equity~~ ~~funds~~Investment related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs capitalized during the years ended December 31, 2009, 2008 and 2007, were $3 million, $3 million and $6 million. These debt amounts are included as a reduction to interest and debt expense on our income statement. The equity portion is calculated using the most recent FERC-approved equity rate of return. The equity rate based on cost of service amounts capitalized (exclusive of taxes) during the years ended December 31, 2009, 2008 and 2007, were $6 million, $6 million and $12 million. These equity amounts are included in other income on our income statement.Divestitures/Impairments

27We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows.

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Asset and Investment Impairments

We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our carrying value based on either (i) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an unconsolidated affiliate. If an impairment is indicated, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of the asset downward, if necessary, to its estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sale, among other factors.

Revenue Recognition

Our revenues are primarily generated from natural gas transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period ~~regardless of the amount of natural gas that is transported or stored~~. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. For contracts with step-up or step-down rate provisions that are not related to changes in levels of service, we recognize reservation revenues ratably over the contract life. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts of gas we use for operating purposes. We recognize revenue on gas not used in operations from our shippers when we retain the volumes at the market price required under our tariffs. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

Environmental Costs. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.

Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that~~, when~~ ~~fully analyzed,~~ indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

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Income Taxes

El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, and (ii) each company in a tax loss position will accrue a benefit to the extent its deductions, including general business credits, can be utilized in the consolidated returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments.

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We record income taxes on a separate return basis. Pursuant to El Paso’s policy, we record current income taxes based on our taxable income and we provide for deferred income taxes to reflect estimated future tax payments and receipts. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. We account for tax credits under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. We reduce deferred tax assets by a valuation allowance when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision, either up or down, in future periods based on new facts or circumstances.

We are required to evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired and we are required to meet a more-likely-than-not threshold (i.e. a greater than 50 percent likelihood of a tax position being sustained under examination) prior to recording a tax benefit. Additionally, for tax positions meeting this more-likely-than-not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon effective settlement. For a further discussion of this accounting standard, see Note 3.

Accounting for Asset Retirement Obligations

We record a liability for legal obligations associated with the replacement, removal or retirement of our long-lived assets in the period the obligation is incurred. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is ~~also~~ recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the accretion of the liabilities described above.

Postretirement Benefits

We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid ~~out~~ under the plan. These contributions are invested until the benefits are paid ~~out~~ to plan participants. WeThe ~~record the~~ net benefit cost ~~related~~of to this plan is recorded in our income statement. ~~This~~and ~~net benefit cost~~ is a function of many factors including benefits earned during the year by plan participants (which is a function of factors such as the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement benefit plan, see Note 9.

In accounting for our postretirement benefit plan, we record an asset or liability based on the over funded or under funded status of the plan. Any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions are recorded as either a regulatory asset or liability.

Effective January 1, 2008, we adopted the provisions of an accounting standard update related to the measurement date and changed the measurement date of our postretirement benefit plan from September 30 to December 31. The adoption of the measurement date provisions of this standard did not have a material impact on our financial statements.

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Effective December 31, 2009, we expanded our disclosures about postretirement benefit plan assets as a result of new accounting disclosure requirements. See Note 9 for these expanded disclosures.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2009, the following accounting standards had not yet been adopted by us.

Transfers of Financial Assets. In June 2009, the FASB updated accounting standards on financial asset transfers. Among other items, this update eliminated the concept of a qualifying special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated or not. The changes are effective for existing QSPEs as of January 1, 2010 and for transactions entered into on or after January 1, 2010. The adoption of this accounting standard in January 2010 did not have a material impact on our financial statements as we amended our existing accounts receivable sales program in January 2010 (see Note 12).

Variable Interest Entities. In June 2009, the FASB updated accounting standards for variable interest entities to revise how companies determine the primary beneficiaries of these entities, among other changes. Companies will be required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required. The adoption of this accounting standard in January 2010 did not have a material impact on our financial statements.

2. Loss on Long-Lived Assets

During 2008, we recorded impairments of $25 million, including an impairment related to our Essex-Middlesex lateral project due to its prolonged permitting process.

3. Income Taxes

Components of Income Tax Expense. The following table reflects the components of income tax expense included in net income for each of the three years ended December 31:

	2009			2008			2007
	2010			2009			2008
	(In millions)
Current
Federal	$	76(8	)(1)	$	5476		$	(154	)
State		13			31			43
		77			57			3
		(5	)		77			57
Deferred
Federal		(764	)		(7	)		857
State		98			79			37
		2			14			88
		72			2			14
Total income tax expense	$	7967		$	7179		$	9171

30____________

(1) During 2010, we utilized a portion of our net operating loss carryover which resulted in a tax benefit for the year ended December 31, 2010.

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Effective Tax Rate Reconciliation. Our income tax expense differs from the amount computed by applying the statutory federal income tax rate of 35 percent for the following reasons for each of the three years ended December 31:

	2009			2008			2007
	2010			2009			2008
	(In millions, except for rates)
Income tax expense at the statutory federal rate of 35%	$	7260		$	6472		$	8564
State income taxes, net of federal income tax effect		7			7			57
Other		—			—			1
Income tax expense	$	67		$	79		$	71
Income tax expense	$	79		$	71		$	91
Effective tax rate		39	%		38	%		39	%
Effective tax rate		38	%		39	%		37	%

Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:

		2009		2008
	2010		2009
	(In millions)	~~(In millions)~~
Deferred tax liabilities
Property, plant and equipment	$	1,~~494~~500	$	1,~~456~~494
Other		76		127
Total deferred tax liability		1,~~501~~506		1,~~468~~501
Deferred tax assets
Net operating loss and credit carryovers
U.S. federal		5426		2254
State		2119		2421
Other liabilities		~~119~~81		~~116~~119
Total deferred tax asset		~~194~~126		~~162~~194
Net deferred tax liability	$	1,~~307~~380	$	1,~~306~~307

We believe it is more likely than not that we will realize the benefit of our deferred tax assets due to expected future taxable income, including the effect of future reversals of existing taxable temporary differences primarily related to depreciation.

Net Operating Loss (NOL) Carryovers. The table below presents the details of our federal and state NOL carryover periods as of December 31, ~~2009~~2010:

		2011-2014		2015-2019		2020-2029	Total
	2011		2012-2015		2016-2020		2021-2030		Total
	(In millions)
U.S. federal NOL	$	—	$	58—	$	96—	$	~~154~~73	$	73
State NOL		521		~~308~~97		~~181~~281		~~541~~153		532

Usage of our U.S. federal carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.

Unrecognized Tax Benefits ~~(Liabilities) for Uncertain Tax Matters~~. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. With a few exceptions, we and El Paso are no longer subject to state and local income tax examinations by tax authorities for years prior to 1999 and U.S. income tax examinations for years prior to 2007. In November 2009, the Internal Revenue Service’s examination of El Paso’s U.S. income tax returns for 2005 and 2006 was settled at the appellate level. The settlement of the issues raised in this examination did not materially impact our results of operations, financial condition or liquidity. For years in which our returns are still subject to review, our unrecognized tax benefits ~~(liabilities~~ ~~for uncertain tax matters)~~ could increase or decrease our income tax expense and our effective income tax rates as these matters are finalized. We are currently unable to estimate the range of potential impacts the resolution of any contested matters could have on our financial statements. The following table shows the change in our unrecognized tax benefits:

	2010			2009
	(In millions)
Amount at January 1	$	16		$	17
Addition:
Tax positions taken in prior years		6			—
Reduction:
Settlements with taxing authorities		(4	)		(1	)
Amount at December 31	$	18		$	16

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Upon the adoption of a new income tax accounting standard related to accounting for uncertain tax matters, and a related amendment to our tax sharing agreement with El Paso, we recorded a reduction of $15 million to the January 1, 2007 balance of retained earnings. As of December 31, ~~2009~~2010 and ~~2008, we had unrecognized tax benefits of $16 million and $17 million. As of December 31,~~ 2009 ~~and 2008~~, approximately $15 million (net of federal tax benefits) of unrecognized tax benefits and associated interest and penalties would affect our income tax expense and our effective income tax rate if recognized in future periods. While the amount of our unrecognized tax benefits could change in the next twelve months, we do not expect this change to have a significant impact on our results of operations or financial position.

We ~~recognize~~ classify interest and penalties related to unrecognized tax benefits inas income ~~tax expense~~taxes onin our ~~income~~financial ~~statement~~statements. As of December 31, ~~2009~~2010 and ~~2008~~2009, we had liabilities for interest and penalties related to our unrecognized tax benefits of approximately $4 million and $7 million. During both ~~2009~~2010 and ~~2008~~2009, we accrued less than $1 million of interest. In addition, during 2010 we settled a state tax audit which generated a reduction of $3 million to the interest and penalties liability related to our unrecognized tax benefits.

4. Fair Value of Financial Instruments

At December 31, ~~2009~~ 2010 and ~~2008~~2009, the carrying amounts of cash and cash equivalents and trade receivables and payables ~~are~~represented ~~representative of their~~ fair value because of the short-term nature of these instruments. At December 31, ~~2009~~ 2010 and ~~2008~~2009, we had an interest bearing ~~notes~~note receivable from El Paso of approximately $1.0 billion ~~and $0.8 billion~~ due upon demand, with a variable interest rate of 1.5% ~~and 3~~.~~2%.~~ While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of ~~these notes~~this note receivable approximates the carrying value due to the ~~notes~~note being due on demand and the market-based nature of the interest rate.

In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows at December 31:

	2009				2008
	2010				2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt	$	1,846	$	2,086	$	1,605	$	1,311
Long-term debt, including current maturities	$	1,851	$	2,071	$	1,846	$	2,086

5. Regulatory Assets and Liabilities

Our ~~current and non-current~~ regulatory assets are included in other current and non-current assets on our balance sheets. Our regulatory asset and liability balances are recoverable or reimbursable over various periods. Below are the details of our regulatory assets and liabilities at December 31:

	2009		2008
	2010		2009
	(In millions)
Current regulatory assets	$	3	$	23
Non-current regulatory assets
Taxes on capitalized funds used during construction		3138		2931
Postretirement benefits		42		104
Other		146		814
Total non-current regulatory assets		4946		4749
Total regulatory assets	$	5249	$	4952
Current regulatory liabilities
Environmental	$	2878	$	—28
Other		—		3
Total current regulatory liabilities		78		28
Total current regulatory liabilities		28		3
Non-current regulatory liabilities
Environmental		~~112~~44		~~157~~112
Postretirement benefits		2935		2229
Other		1211		12
Total non-current regulatory liabilities		~~153~~90		~~191~~153
Total regulatory liabilities	$	~~181~~168	$	~~194~~181

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The significant regulatory assets and liabilities include:

Taxes on Capitalized Funds Used During Construction:. ~~These~~Regulatory ~~regulatory~~ asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. Taxes on capitalized funds used during construction ~~are amortized~~ and the offsetting deferred income taxes are included in the rate base~~. Both~~ and are recovered over the depreciable lives of the long-lived asset to which they relate.

Postretirement Benefits:. ~~These~~Represents ~~balances represent deferred amounts related to~~ unrecognized gains and losses or changes in actuarial assumptions related to our postretirement benefit plan and differences in the postretirement benefit related amounts expensed and the amounts recovered in rates. Postretirement benefit amounts have been included in the rate base computations and are recoverable in such periods as benefits are funded.

Environmental:. Includes amounts collected, substantially in excess of certain ~~Polychlorinated~~polychlorinated ~~Biphenyls~~ biphenyls (PCB) environmental remediation costs to date, through a surcharge to our customers under a settlement approved by the FERC in November of 1995. At this time the environmental liability is not deducted from the rate base on which we are allowed to earn current return. For a further discussion of the PCB matter, see Note 8.

6. Property, Plant and Equipment

Additional Acquisition Costs. Included in our property balances are additional acquisition costs assigned to utility plant, which represent the excess of allocated purchase costs over the historical costs of the facilities. At December 31, ~~2009~~2010 and ~~2008~~2009, additional acquisition costs assigned to utility plant was approximately $2.4 billion and accumulated depreciation was approximately $~~418~~458 million and $~~379~~418 million, respectively. These additional acquisition costs are being amortized on a straight-line basis over 62 years using the ~~life~~same ofrates as the related ~~pipeline~~ assets, and are not recoverable in our rates under current FERC policies. Our amortization expense related to additional acquisition costs assigned to utility plant was approximately $3940 million, $4139 million and $39 41 million for the years ended December 31, ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008.

~~Asset~~Capitalized ~~Retirement~~Costs ~~Obligations~~During Construction. We Interest ~~have~~costs ~~legal~~capitalized ~~obligations~~were ~~associated~~$6 ~~with the retirement of our natural gas pipeline~~million, ~~transmission~~$3 ~~facilities~~million and ~~storage~~$3 ~~wells,~~million asduring ~~well~~the asyears ~~obligations related~~ended toDecember El31, ~~Paso’s~~2010, ~~corporate~~2009 ~~headquarters building. Our legal obligations primarily involve purging~~ and ~~sealing the pipeline if it is abandoned~~2008. WeEquity ~~also have~~amounts ~~obligations~~capitalized towere ~~remove~~$13 ~~hazardous~~million, ~~materials~~$6 ~~associated~~million ~~with our natural gas transmission facilities~~ and in$6 Elmillion ~~Paso’s~~(exclusive ~~corporate~~of ~~headquarters~~taxes) ifduring ~~these facilities~~the ~~are~~years ~~ever~~ended ~~demolished~~December 31, ~~replaced~~2010, or2009 ~~renovated. We continue to evaluate our asset retirement obligations~~ and ~~future developments could impact the amounts we record~~2008.

~~Where~~Construction weWork ~~can reasonably~~In ~~estimate~~Progress. ~~the~~At ~~asset~~December ~~retirement obligation~~31, we2010 ~~accrue a liability based on an estimate of the timing~~ and ~~amount of settlement. In estimating our asset retirement obligations~~2009, we ~~utilize~~had ~~several~~$406 ~~assumptions,~~million ~~including~~and a$271 ~~projected inflation~~million ~~rate~~ of ~~2.5~~construction ~~percent,~~work ~~and credit-adjusted discount rates that currently range from six to nine percent based on when the liabilities were recorded. We record changes~~ in ~~estimates~~progress ~~based~~included ~~on changes~~ in ~~the expected amount and timing of payments to settle~~ our ~~obligations. We intend on operating and maintaining our natural gas pipeline and storage system as long as supply and demand for natural gas exists~~property, ~~which~~plant ~~we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline~~ and ~~storage system assets because these assets have indeterminate lives~~equipment.

Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transportation facilities primarily involve purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities if they are ever demolished or replaced. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. In estimating our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from five to 12 percent based on when the liabilities were recorded. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. We intend on operating and maintaining our natural gas pipeline and storage systems as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.

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The net asset retirement obligation as of December 31 reported on our balance sheets in current and other non-current liabilities, and the changes in the net liability for the years ended December 31 were as follows:

	2009			2008
	2010			2009
	(In millions)
Net asset retirement obligation at January 1	$	4291		$	1742
Liabilities settled		(626	)		(36	)
Accretion expense		2			12
Changes in estimate(1)		53			27
Liabilities incurred		5			—
Net asset retirement obligation at December 31(2)	$	91		$	42
Changes in estimate (1)		(43	)		53
Net asset retirement obligation at December 31(2)	$	29		$	91

____________

(1) Reflects ~~(2) Increase in estimate primarily due to~~ updated information received on our hurricane related asset retirement obligations. ~~For the years ended December 31, 2009 and 2008, approximately $66 million and $5 million of this amount is reflected in current liabilities.~~

33(2) For the years ended December 31, 2010 and 2009, approximately $28 million and $66 million of this amount are reflected in current liabilities.

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7. Debt and Credit Facilities

Debt. Our long-term debt consisted of the following at December 31:

	2009		2008
	2010		2009
	(In millions)
6.0% Debentures due December 2011	$	86	$	86
8.0% Notes due February 2016		250		—250
7.5% Debentures due April 2017		300		300
7.0% Debentures due March 2027		300		300
7.0% Debentures due October 2028		400		400
8.375% Notes due June 2032		240		240
7.625% Debentures due April 2037		300		300
		1,876		1,~~626~~876
Less: Unamortized discount		30		21
Less: Current maturities		86		—
Total long-term debt	$	1,846	$	1,605
Unamortized discount		25		30
Total long-term debt	$	1,765	$	1,846

In January 2009, we issued $250 million of 8.00% senior notes due in February 2016 and received proceeds of $234 million, net of issuance costs.

Credit Facility. We are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, ~~2009~~2010, El Paso had approximately $0.89 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. Our common stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.

Under El Paso’s $1.5 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; and (v) potential limitations on our ability to declare and pay dividends. For the year ended December 31, ~~2009~~2010, we were in compliance with our debt-related covenants.

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8. Commitments and Contingencies

Legal Proceedings

~~Gas Measurement Cases.~~ We and a ~~number of~~ our affiliates ~~were~~are named defendants in ~~actions~~numerous legal proceedings and claims that ~~generally allege~~arise ~~mismeasurement~~in the ordinary course of ~~natural~~our ~~gas~~business. ~~volumes~~For ~~and/or~~each ~~heating~~of ~~content~~these ~~resulting~~matters, in we evaluate the ~~underpayment~~merits of ~~royalties.~~the ~~The~~case ~~first~~or ~~set~~claim, ofour ~~cases~~exposure ~~was~~to ~~filed~~the inmatter, ~~1997~~possible bylegal ~~an individual~~or ~~under~~settlement strategies and the ~~False~~likelihood ~~Claims~~of ~~Act~~an ~~and~~unfavorable ~~have~~outcome. ~~been~~If ~~consolidated~~we ~~for~~determine ~~pretrial purposes~~that ~~(In~~an ~~re:~~unfavorable ~~Natural Gas~~outcome ~~Royalties~~is ~~Qui~~probable ~~Tam Litigation~~and can be estimated, ~~U.S.~~we ~~District~~establish ~~Court~~the ~~for~~necessary accruals. While the ~~District~~outcome of ~~Wyoming).~~these ~~These complaints~~matters ~~allege~~cannot anbe ~~industry-wide~~predicted ~~conspiracy~~with tocertainty, ~~underreport~~and ~~the~~there ~~heating~~are ~~value as~~still ~~well~~uncertainties asrelated to the ~~volumes~~costs ofwe ~~the~~may ~~natural~~incur, ~~gas~~based ~~produced~~upon ~~from~~our ~~federal~~evaluation and ~~Native American~~experience ~~lands.~~to ~~In October 2006~~date, ~~the~~we ~~U.S.~~had ~~District~~no ~~Judge~~accruals ~~issued~~for anour ~~order dismissing~~outstanding ~~all~~legal ~~claims~~proceedings ~~against~~at ~~all~~December ~~defendants~~31, 2010. It Inis ~~March~~possible, ~~2009~~however, ~~the~~that ~~Tenth~~new ~~Circuit Court~~information ofor ~~Appeals~~future ~~affirmed~~developments ~~the~~could ~~dismissals~~require ~~and~~us into ~~October~~reassess ~~2009,~~our ~~the~~potential ~~plaintiff’s appeal~~exposure related to ~~the~~these ~~United~~matters ~~States~~and ~~Supreme~~establish ~~Court~~accruals ~~was denied~~accordingly.

Similar allegations were filed in a set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. The plaintiffs seek an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. In September 2009, the court denied the motions for class certification. The plaintiffs have filed a motion for reconsideration. Our costs and legal exposure related to this lawsuit and claim are not currently determinable.

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In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and establish our accruals accordingly, and these adjustments could be material. At December 31, 2009, we had accrued approximately $7 million for our outstanding legal matters.

Environmental Matters

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect ~~on the environment~~ of the disposal or release of specified substances at current and former operating sites. At December 31, ~~2009~~2010 and ~~2008~~2009, we had accrued approximately $54 million and $65 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $7 million at December 31, ~~2009~~2010.

Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will ~~expend~~spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

PCB Cost Recoveries and Refund. Since 1994, we have been conducting remediation activities at certain of our compressor stations associated with PCBs and other hazardous materials. We have collected amounts, substantially in excess of remediation costs to date, through a surcharge to our customers under a settlement approved by the FERC in November of 1995. In November 2009, the FERC approved an amendment to the 1995 settlement that provides for interim refunds over a three year period of approximately $157 million of our collected amounts plus interest of 8%. InThrough December ~~2009~~31, 2010, we have refunded approximately $3058 million to our customers. Our refund obligations are recorded as regulatory liabilities on our balance sheet and as of December 31, ~~2009~~2010, we have classified approximately $2878 million as current liabilities based on the timing of when these amounts are expected to be refunded to our customers.

~~Comprehensive~~Superfund ~~Environmental Response,~~Matters. Included ~~Compensation~~in ~~and~~our ~~Liability~~recorded ~~Act~~environmental ~~(CERCLA)~~liabilities ~~Matters.~~are Weprojects where we have received notice that we ~~could~~have bebeen designated, or ~~have been asked for information to determine whether we~~ could be designated, as a Potentially Responsible Party (PRP) ~~with respect to four active sites~~ under the ~~CERCLA~~Comprehensive orEnvironmental ~~state~~Response, ~~equivalents. We~~Compensation ~~have sought to resolve our liability as a PRP at these sites through indemnification by third parties~~ and ~~settlements~~Liability ~~which~~Act ~~provide for payment of our allocable share of remediation costs. As of December 31~~(CERCLA), ~~2009,~~commonly weknown ~~have estimated our share of the remediation costs at these sites to be between $1 million and $2 million. Because the clean-up costs are estimates and are subject to revision~~ as ~~more information becomes available about the extent of remediation required~~Superfund, ~~and~~or instate ~~some~~equivalents ~~cases~~for wefour ~~have~~active ~~asserted a defense to any liability, our estimates could change~~sites. ~~Moreover,~~Liability ~~liability~~ under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We ~~Our~~consider ~~understanding of~~ the financial strength of other PRPs ~~has been considered, where appropriate,~~ in estimating our liabilities. Accruals for these ~~matters~~issues are included in the environmental reserve discussed above.

~~For~~We ~~2010,~~expect ~~we estimate~~to ~~that~~make ~~our~~capital ~~total~~expenditures ~~remediation~~for ~~expenditures~~environmental ~~will~~matters beof approximately $1 9 million in the aggregate for 2011 through 2015, including capital expenditures associated with the impact of the EPA rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which ~~will~~are subject to regulations which have to be ~~expended~~in ~~under~~compliance ~~government~~by ~~directed~~October ~~clean-up plans~~2013.

It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.36

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~~Regulatory Matter~~It is possible that new information or future developments could require us to reassess our potential exposure related to environmental matters. We may incur significant costs and liabilities in order to comply with existing environmental laws and regulations. It is also possible that other developments, such as increasingly strict environmental laws, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

~~Notice~~Rates of Proposed Rulemaking. In October 2007, the Minerals Management Service (MMS) issued a notice of proposed rulemaking that is applicable to pipelines located in the Outer Continental Shelf (OCS). If adopted, the proposed rules would substantially revise MMS OCS pipeline and ~~rights-of-way~~Regulatory regulations. The proposed rules would have the effect of (i) increasing the financial obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (ii) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights of way in the OCS; and (iii) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.Matter

Rate Case. In November 2010, we filed a rate case with the FERC proposing an increase in base tariff rates, including a proposed change in our rate structure. In December 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to June 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not currently determinable.

Other Commitments

Capital Commitments. At December 31, ~~2009~~2010, we had capital commitments of approximately $~~268~~320 million primarily related to our 300 Line ~~expansion project~~Project, all of which ~~$63 million~~ will be ~~spent in 2010, $200 million will~~ be spent in 2011 ~~and $5 million will be spent in 2012~~. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Purchase Obligations. We have entered into unconditional purchase obligations primarily for transportation, storage and other services, totaling $~~127~~103 million at December 31, ~~2009~~2010. Our annual obligations under these purchase obligations are $4235 million in ~~2010~~2011, $34 25 million in ~~2011~~2012, $1914 million in ~~2012~~2013, $97 million in ~~2013~~2014, $67 million in ~~2014~~ 2015, and $1715 million in total thereafter.

Operating Leases. We lease property, facilities and equipment under various operating leases. Future minimum annual rental commitments under our operating leases at December 31, ~~2009~~ 2010, were as follows:

Year Ending December 31,	(In millions)	~~(In millions)~~
2010		$	1
2011	$	1
2011			1
Thereafter		3
2012			1
Total	$	4
Thereafter			2
Total		$	5

Rental expense on our lease obligations for each of the years ended December 31, ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008 was $2 million. These amounts include rent allocated to us from El Paso.

Other Commercial Commitments. We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Our obligations under these easements are not material to our results of operations.

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9. Retirement Benefits

Pension and Retirement Savings Plans. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our former employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six percent of eligible compensation and can make additional discretionary matching contributions depending on ~~its~~ El Paso’s operating performance relative to its peers. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits Plan. We provide postretirement medical and life insurance benefits for a closed group of employees who were eligible to retire on December 31, 1996, and did so before July 1, 1997. Medical benefits for this closed group may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. Employees in this group who retire after July 1, 1997 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $5 million to our postretirement benefit plan in 2010.

Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. In accounting for our postretirement benefit plan, we record an asset or liability for our postretirement benefit plan based on the over funded or under funded status. In March 2007, the FERC issued guidance requiring regulated pipeline companies to record a regulatory asset or liability for any deferred amounts related to unrecognized gains and losses or changes in actuarial assumptions that would otherwise be recorded in accumulated other comprehensive income for non-regulated entities. Upon adoption of this FERC guidance, we reclassified $3 million from accumulated other comprehensive loss to a regulatory liability.

The table below provides information about our postretirement benefit plan. In 2008, we adopted the FASB’s revised measurement date provisions for other postretirement benefit plans and the information below for 2008 is presented and computed as of and for the fifteen months ended December 31, 2008. For 2009, the information is presented and computed as of and for the twelve months ended December 31, 2009.

	December 31, 2009			December 31, 2008
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation - beginning of period	$	21		$	22
Interest cost		1			1
Participant contributions		1			2
Actuarial gain		(4	)		—
Benefits paid(1)		(1	)		(4	)
Accumulated postretirement benefit obligation - end of period	$	18		$	21
Change in plan assets:
Fair value of plan assets - beginning period	$	23		$	29
Actual return on plan assets		6			(9	)
Employer contributions		4			5
Participant contributions		1			2
Benefits paid		(1	)		(4	)
Fair value of plan assets - end of period	$	33		$	23
Reconciliation of funded status:
Fair value of plan assets	$	33		$	23
Less: accumulated postretirement benefit obligation		18			21
Net asset at December 31	$	15		$	2

____________

(1) Amounts shown net of a subsidy of less than $1 million for each of the years ended December 31, 2009 and 2008 related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

~~Table~~Postretirement Benefits Plan. We provide postretirement medical and life insurance benefits for a closed group of ~~Contents~~employees who were eligible to retire on December 31, 1996, and did so before July 1, 1997. Medical benefits for this closed group may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs and El Paso reserves the right to change these benefits. Employees in this group who retire after July 1, 1997 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates. To the extent actual costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $5 million to our postretirement benefit plan in 2011.

~~Plan~~Accumulated ~~Assets.~~Postretirement ~~The~~Benefit ~~primary investment~~Obligation, ~~objective~~Plan ofAssets ~~our~~and ~~plan~~Funded isStatus. toIn ~~ensure~~accounting ~~that,~~for ~~over~~our ~~the~~postretirement ~~long-term~~benefit ~~life~~plan, ~~of the~~we ~~plan~~record an ~~adequate~~asset ~~pool~~or ofliability ~~sufficiently~~based ~~liquid~~on ~~assets exists to meet~~ the ~~benefit~~ ~~obligations~~over tofunded ~~retirees~~or ~~and~~under ~~beneficiaries.~~funded ~~Investment objectives are long-term in nature covering typical market cycles~~status. Any ~~shortfall~~deferred ofamounts ~~investment performance~~related ~~compared~~ to ~~investment~~unrecognized ~~objectives~~gains isand ~~generally~~losses ~~the~~or ~~result~~changes ~~of economic~~in ~~and~~actuarial ~~capital~~assumptions ~~market~~are ~~conditions.~~recorded ~~Although~~either ~~actual~~as ~~allocations~~a ~~vary~~regulatory ~~from time~~asset toor ~~time~~liability ~~from~~as ~~our~~allowed ~~targeted~~by ~~allocations,~~ the ~~target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities~~FERC. WeThese ~~may~~amounts ~~invest~~would ~~plan~~otherwise ~~assets~~be recorded in aaccumulated ~~manner~~other ~~that~~comprehensive ~~replicates,~~income ~~to the~~for ~~extent~~non-regulated ~~feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively~~entities.

WeThe ~~use~~table ~~various methods~~below toprovides ~~determine~~information ~~the~~about ~~fair values of the assets in~~ our ~~other~~ postretirement benefit ~~plans, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets~~plan. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2009, our assets are comprised of an exchange-traded mutual fund with a fair value of $2 million and common/collective trusts with a fair value of $31 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common/collective trusts are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. We may adjust the fair value of our common/collective trusts, when necessary, for factors such as liquidity or risk of nonperformance by the issuer. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2009 and 2008.

Expected Payment of Future Benefits. As of December 31, 2009, we expect the following benefit payments under our plan:

	December 31,
	2010			2009
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation – beginning of period	$	18		$	21
Interest cost		1			1
Participant contributions		1			1
Actuarial gain		—			(4	)
Benefits paid(1)		(2	)		(1	)
Accumulated postretirement benefit obligation – end of period	$	18		$	18
Change in plan assets:
Fair value of plan assets – beginning period	$	33		$	23
Actual return on plan assets		4			6
Employer contributions		5			4
Participant contributions		1			1
Benefits paid		(2	)		(1	)
Fair value of plan assets – end of period	$	41		$	33
Reconciliation of funded status:
Fair value of plan assets	$	41		$	33
Less: accumulated postretirement benefit obligation		18			18
Net asset at December 31	$	23		$	15

Year Ending December 31,	Expected Payments(1)
	(In millions)
2010	$	2
2011		2
2012		2
2013		2
2014		2
2015 - 2019		7

____________

(1) Amounts ~~Includes~~shown net of a ~~reduction~~subsidy of less than $1 million infor each of the years ~~2010~~ended –December ~~2014~~31, 2010 and ~~approximately~~2009 ~~$1 million in aggregate for 2015 – 2019 for an expected subsidy~~ related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Plan Assets. The primary investment objective of our plan is to ensure that, over the long-term life of the plan an adequate pool of sufficiently liquid assets exists to meet the benefit obligations to retirees and beneficiaries. Investment objectives are long-term in nature covering typical market cycles. Any shortfall of investment performance compared to investment objectives is generally the result of economic and capital market conditions. Although actual allocations vary from time to time from our targeted allocations, the target allocations of our postretirement plan’s assets are 65 percent equity and 35 percent fixed income securities. We may invest plan assets in a manner that replicates, to the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond Index to achieve equity and fixed income diversification, respectively.

We use various methods to determine the fair values of the assets in our other postretirement benefit plan, which are impacted by a number of factors, including the availability of observable market data over the contractual term of the underlying assets. We separate these assets into three levels (Level 1, 2 and 3) based on our assessment of the availability of this market data and the significance of non-observable data used to determine the fair value of these assets. As of December 31, 2010, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $39 million. As of December 31, 2009, assets were comprised of an exchange-traded mutual fund with a fair value of $2 million and common collective trust funds with a fair value of $31 million. Our exchange-traded mutual fund invests primarily in dollar-denominated securities, and its fair value (which is considered a Level 1 measurement) is determined based on the price quoted for the fund in actively traded markets. Our common collective trust funds are invested in approximately 65 percent equity and 35 percent fixed income securities, and their fair values (which are considered Level 2 measurements) are determined primarily based on the net asset value reported by the issuer, which is based on similar assets in active markets. Certain restrictions on withdrawals exist for these common collective trust funds where the issuer reserves the right to temporarily delay withdrawal in certain situations such as market conditions or at the issuer’s discretion. We do not have any assets that are considered Level 3 measurements. The methods described above may produce a fair value that may not be indicative of net realizable value or reflective of future fair values, and there have been no changes in the methodologies used at December 31, 2010 and 2009.

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~~Actuarial~~Expected ~~Assumptions~~Payment ~~and Sensitivity~~of ~~Analysis~~Future Benefits. ~~Accumulated~~As ~~postretirement~~of ~~benefit~~December ~~obligations~~31, ~~and net~~2010, ~~benefit~~we ~~costs~~expect ~~are~~the ~~based on actuarial estimates and assumptions. The~~ following ~~table~~benefit ~~details~~payments ~~the~~under ~~weighted average actuarial assumptions used in determining~~ our ~~postretirement~~ plan ~~obligations and net benefit costs for 2009, 2008 and 2007~~:

	2009			2008		2007
Year Ending December 31,		Expected Payments(1)
	(Percent)
		(In millions)
Assumptions related to benefit obligations at December 31, 2009 and 2008 and September 30, 2007 measurement dates:
2011		$	2
Discount rate		5.37			5.95		6.05
2012			2
Assumptions related to benefit costs at December 31:
2013			2
Discount rate		5.95			6.05		5.50
2014			2
Expected return on plan assets(1)		8.00			8.00		8.00
2015			2
2016 - 2020			6

____________

(1) Includes a reduction of less than $1 million in each of the years 2011 – 2015 and approximately $1 million in aggregate for 2016 – 2020 for an expected subsidy related to the Medicare Prescription Drug, Improvement, and Modernization Act of 2003.

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations and net benefit costs for 2010, 2009 and 2008:

	2010		2009		2008
	(Percent)
Assumptions related to benefit obligations at December 31:
Discount rate		4.82		5.37		5.95
Assumptions related to benefit costs for the year ended December 31:
Discount rate		5.37		5.95		6.05
Expected return on plan assets(1)		7.75		8.00		8.00

____________

(1) The expected return on plan assets is a pre-tax rate of return based on our targeted portfolio of investments. Our postretirement benefit plan’s investment earnings are subject to unrelated business income taxes at a rate of 35%. The expected return on plan assets for our postretirement benefit plan is calculated using the after-tax rate of return.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 87.04 percent, gradually decreasing to 5.0 percent by the year ~~2015~~2016. ~~Changes~~A inone-percentage ~~the assumed~~point ~~health~~change ~~care~~would ~~cost trend rates do~~ not have had a ~~material~~significant ~~impact~~effect on the ~~amounts~~ ~~reported~~accumulated ~~for~~postretirement ~~our~~benefit obligation or interest ~~costs~~cost oras ~~our~~of ~~accumulated~~and ~~postretirement benefit~~for ~~obligations~~the years ended December 31, 2010 and 2009.

Components of Net Benefit Income. For each of the years ended December 31, the components of net benefit income are as follows:

	2009			2008			2007
	2010			2009			2008
	(In millions)
Interest cost	$	1		$	1		$	1
Expected return on plan assets		(12	)		(1	)		(1	)
Net benefit income	$	—(1	)	$	—		$	—

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10. Transactions with Major Customer

The following table shows revenues from our major customer for each of the three years ended December 31:

	2009		2008		2007
	2010		2009		2008
	(In millions)
National Grid USA and Subsidiaries (1)	$	109	$	109	$	77
National Grid USA and subsidiaries	$	116	$	109	$	109

~~____________~~11. Accounts Receivable Sales Program

During 2009, we had an agreement to sell a senior interest in certain accounts receivable (1which are short-term assets that generally settle within 60 days) to a third party financial institution (through a wholly-owned special purpose entity), and we retained a subordinated interest in those receivables. The sale of the senior interest qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. InDuring ~~2007~~the years ended December 31, ~~National~~ ~~Grid~~2009 ~~USA~~and 2008, we received $481 million and ~~Subsidiaries~~$430 ~~did~~million ~~not~~of ~~represent~~cash ~~more~~related to the sale of the senior interest, collected $462 million and $521 million from the subordinated interest we retained in the receivables, and recognized a loss of less than 10$1 ~~percent~~million and approximately $1 million during 2009 and 2008 on these transactions. At December 31, 2009, the third party financial institution held $40 million of senior interest and we held $43 million of subordinated interest. Our subordinated interest was reflected in accounts receivable on our ~~revenues~~ balance sheet. In January 2010, we terminated this accounts receivable sales program and paid $40 million to acquire the senior interest. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interest, and cash paid to terminate the program, as operating cash flows on our statement of cash flows.

11In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third party financial institution that qualifies for sale accounting under the updated accounting standards related to financial asset transfers. ~~Supplemental~~ Under ~~Cash~~this ~~Flow~~program, ~~Information~~we sell receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity). At December 31, 2010, the third party financial institution held $75 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. During the year ended December 31, 2010, we sold approximately $943 million of accounts receivable to the third party financial institution, for which we received approximately $508 million of cash up front and had a deferred purchase price of approximately $435 million. We received approximately $399 million of cash related to the deferred purchase price when the underlying receivables were collected during 2010. As of December 31, 2010, we had not collected approximately $35 million of deferred purchase price related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets). We recognized a loss of less than $1 million on our accounts receivable sales for the year ended December 31, 2010. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales program as operating cash flows on our statement of cash flows.

~~The~~Under ~~following~~both ~~table contains~~the ~~supplemental~~prior ~~cash~~and ~~flow~~current ~~information~~accounts receivable sales programs, we serviced the underlying receivables for ~~each~~a fee. The fair value of these servicing agreements as well as the ~~three~~fees earned were not material to our financial statements for the years ended December 31:, 2010, 2009 and 2008.

	2009		2008		2007
	(In millions)
Interest paid, net of capitalized interest	$	130	$	120	$	116
Income tax payments		60		12		121

The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to control, direct, or exert significant influence over its overall activities since our receivables do not comprise a significant portion of its operations.

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12. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

Bear Creek Storage Company, LLC (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Southern Natural Gas Company, our affiliate. We account for our investment in Bear Creek using the equity method of accounting. During ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008, we received $1314 million, $16 13 million and $2716 million in ~~dividends~~cash distributions from Bear Creek. Also, during 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to us. Included in this amount was a return of capital of $15 million.

Summarized financial information for our proportionate share of Bear Creek as of and for the years ended December 31 is presented as follows:

	2009		2008		2007
	2010		2009		2008
	(In millions)
Operating results data:
Operating revenues	$	1819	$	2018	$	1920
Operating expenses		75		87		8
Income from continuing operations and net income		11		13		13
Income from operations and net income		14		11		13

	2009		2008
	2010		2009
	(In millions)
Financial position data:
Current assets	$	285	$	2728
Non-current assets		52		5552
Current liabilities		12		1
Equity in net assets		7955		8179

Transactions with Affiliates

Cash Management Program and Other ~~Notes~~ Note Receivable. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At December 31, ~~2009~~2010 and ~~2008~~ 2009, we had ~~notes~~a note receivable from El Paso of $1.0 billion ~~and $0~~.8 ~~billion.~~ We classified approximately $93359 million of this receivable as current on our balance sheet at December 31, ~~2009~~2010, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on ~~these~~this variable rate ~~notes~~note was 1.5% at December 31, ~~2009~~ ~~and~~2010 ~~2008 was 1.5%~~ and 32009.~~2%.~~

At December 31, ~~2009~~ ~~and 2008~~2009, we had a non-interest bearing note receivable of $334 million from an El Paso affiliate. ~~This note is~~ reflected as a reduction of our stockholder’s equity. During ~~based~~2010, onwe ~~uncertainties~~collected ~~regarding~~this ~~the~~note ~~timing~~receivable and ~~method through~~then ~~which~~immediately Eldistributed ~~Paso~~the ~~will~~cash ~~settle~~received ~~these~~to ~~balances~~our parent.

Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At December 31, ~~2009~~2010 and ~~2008~~2009, we had net federal and state income taxes ~~payable~~receivable of $754 million and net federal and state income taxes payable of $5875 million. The majority of these balances, as well as deferred income taxes and amounts associated with the resolution of unrecognized tax benefits, will become receivable from or payable to El Paso. See Note 1 for a discussion of our income tax policy.

~~Accounts~~Other ~~Receivable~~Affiliate ~~Sales Program~~Balances. ~~We sell certain accounts receivable to a QSPE whose purpose is solely to invest in our receivables, which are short-term assets that generally settle within 60 days.~~ At ~~both~~ December 31, ~~2009~~2010 and 2008, we received net proceeds of approximately $0.9 billion related to sales of receivables to the QSPE and changes in our subordinated beneficial interests. We recognized losses of less than $1 million on these transactions for both the years ended December 31, 2009 ~~and 2008. As of December 31~~, ~~2009 and 2008,~~ we had ~~approximately~~contractual ~~$83 million~~deposits ~~and~~from ~~$97~~our ~~million~~affiliates of ~~receivables outstanding with the QSPE, for which we received cash of~~ $3910 million and $389 million ~~for December 31, 2009 and 2008, and received subordinated beneficial interests of approximately $43 million and $58 million~~. The QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $40 million and $39 million for December 31, 2009 and 2008. We reflect the subordinated beneficial interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliate in our balance sheets. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectability of the underlying receivables sold to the QSPE. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the receivables and performing all administrative duties for the QSPE which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the years ended December 31, 2009 and 2008.

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InAffiliate ~~January~~Revenues ~~2010,~~and ~~we ceased~~Expenses. ~~selling~~We ~~accounts~~enter ~~receivable~~into totransactions ~~the~~with ~~QSPE~~our ~~and~~affiliates ~~began~~within ~~selling~~the ~~those receivables~~ordinary ~~directly~~course toof aour ~~third~~business ~~party~~and ~~financial~~the ~~institution.~~services Inare ~~return,~~based on the ~~third~~ ~~party~~same ~~financial~~terms ~~institution~~as ~~pays~~non-affiliates. In aaddition, ~~certain~~we ~~amount~~store ofnatural ~~cash~~gas upin ~~front~~an ~~for~~affiliated ~~the receivables,~~storage facility and ~~pays~~utilize the ~~remaining~~pipeline ~~amount~~system ~~owed~~of ~~over~~an ~~time~~affiliate asto ~~cash~~transport issome ~~collected from~~of ~~the~~our ~~receivables~~natural gas.

Other Affiliate Balances. At both December 31, 2009 and 2008, we had contractual deposits from our affiliates of $9 million.

Affiliate Revenues and Expenses. We enter into transactions with our affiliates. In addition, we store natural gas in an affiliated storage facility and utilize the pipeline system of an affiliate to transport some of our natural gas. These transactions are within the ordinary course of our business and the services are based on the same terms as non-affiliates.

In December 2009, we entered into a contract with our affiliate, El Paso Marketing, L.P., to sell up to 22 TBtu of natural gas not used in our operations in 2011 at a price of $6.48 per MMBtu.

El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we allocate costs to our pipeline affiliates for their proportionate share of our pipeline services. The allocations from El Paso and the allocations to our affiliates are based on the estimated level of effort devoted to our operations and the relative size of our and their ~~EBIT~~earnings before interest expense and income taxes, gross property and payroll.

The following table shows overall revenues, expenses and ~~charges~~reimbursements from our affiliates for each of the three years ended December 31:

	2009		2008		2007
	2010		2009		2008
	(In millions)
Revenues from affiliates	$	16	$	20	$	21
Revenues	$	20	$	16	$	20
Operation and maintenance expenses from affiliates		67		60		57
Operation and maintenance expenses		77		67		60
Reimbursements of operating expenses charged to affiliates		45		47		45
Reimbursements of operating expenses		59		45		47

13. Supplemental Selected Quarterly Financial Information (Unaudited)

Our financial information by quarter is summarized below. Due to the seasonal nature of our business, information for interim periods may not be indicative of our results of operations for the entire year.

	Quarters Ended
	March 31		June 30		September 30		December 31		Total
	(In millions)
2010
Operating revenues	$	224	$	200	$	213	$	208	$	845
Operating income		89		59		65		55		268
Net income		39		20		28		16		103
2009
Operating revenues	$	266	$	217	$	221	$	229	$	933
Operating income		114		70		64		73		321
Net income		53		25		20		29		127
2008
Operating revenues	$	245	$	217	$	209	$	236	$	907
Operating income		88		56		49		69		262
Net income		43		22		16		30		111

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SCHEDULE II

TENNESSEE GAS PIPELINE COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, ~~2009~~2010, ~~2008~~2009 and ~~2007~~2008

(In millions)

Description	Balance at Beginning of Period		Charged to Costs and Expenses			Deductions			~~Charged~~Balance toat ~~Other~~End ~~Accounts~~of Period		~~Balance at End of Period~~
2009
2010
Legal reserves	$	—7	$	7—		$	—(7	)	$	—	$	7
Environmental reserves		65		—1			(12	)(21)		—4		5
2008
2009
Environmental reserves	$	10	$	(2	)	$	(2	)(2)	$	—	$	6
Legal reserves	$	—	$	7		$	—		$	7
2007
Environmental reserves		6		—			(1	)(1)		5
Environmental reserves	$	15	$	(2	)(1)	$	(3	)(2)	$	—	$	10
2008
Environmental reserves	$	10	$	(2	)	$	(2	)(1)	$	6

~~____________~~_________

(1) Primarily ~~Represents~~payments amade ~~reduction~~for inenvironmental ~~the estimated costs to complete our internal~~ remediation ~~projects~~activities.

~~(2) Primarily payments made for environmental remediation activities.~~43

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, ~~2009~~2010, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the ~~SEC~~U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and ~~Chief Financial Officer~~CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and ~~Chief~~CFO ~~Financial Officer~~ concluded that our disclosure controls and procedures (as defined in ~~the~~ Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of December 31, ~~2009~~ 2010. See Item 8, Financial Statements and Supplementary Data under Management’s Annual Report on Internal Control Over Financial Reporting.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the fourth quarter of ~~2009~~ 2010 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9A(T). CONTROLS AND PROCEDURES

This annual report does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report. See Item 8, Financial Statements and Supplementary Data, under Management’s Annual Report on Internal Control Over Financial Reporting.

ITEM 9B. OTHER INFORMATION

None.

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PART III

Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, ~~2009~~2010 and ~~2008~~2009 of $~~878~~982,000 and $~~762~~878,000, respectively, were primarily for professional services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Tennessee Gas Pipeline Company and its subsidiaries as well as the review of documents filed with the SEC, related consents in both 2010 and 2009 and the issuance of a comfort ~~letters~~ letter in 2009.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firm for the years ended December 31, ~~2009~~2010 and ~~2008~~ 2009.

Policy for Approval of Audit and Non-Audit Fees

We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its ~~2010~~2011 Annual Meeting of Stockholders.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)	The following documents are filed as a part of this report:

1. Financial statements

The following consolidated financial statements are included in Part II, Item 8 of this report:

	Page
Report of Independent Registered Public Accounting Firm	2123
Consolidated Statements of Income	2224
Consolidated Balance Sheets	2325
Consolidated Statements of Cash Flows	2426
Consolidated Statements of Stockholder’s Equity	2527
Notes to Consolidated Financial Statements	2628

2. Financial statement schedules

Schedule II — Valuation and Qualifying Accounts 4243

All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.

3. Exhibits

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•	may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•	may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the Securities ~~U.S.~~and ~~SEC~~Exchange Commission upon request all constituent instruments defining the rights of holders of our long-term debt and ~~our~~ consolidated subsidiaries not filed asherewith ~~an exhibit hereto~~ for the reason that the total amount of securities authorized under any of such instruments does not exceed 10 percent of our total consolidated assets.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Tennessee Gas Pipeline Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the ~~1st~~28th day of ~~March~~February ~~2010~~2011.

TENNESSEE GAS PIPELINE COMPANY By: /s/ ~~James~~Norman CG. ~~Yardley~~Holmes ~~James~~Norman CG. ~~Yardley~~Holmes President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of Tennessee Gas Pipeline Company and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ James C. Yardley	Chairman of the Board and President	March 1, 2010
/s/ Norman G. Holmes	President and Director	February 28, 2011
James C. Yardley	(Principal Executive Officer)
Norman G. Holmes	(Principal Executive Officer)
/s/ John R. Sult	Senior Vice President and Chief Financial	March 1, 2010
	Executive Vice President and
John R. Sult	Officer (Principal Financial Officer)
/s/ John R. Sult	Chief Financial Officer	February 28, 2011
/s/ Rosa P. Jackson	Vice President and Controller	March 1, 2010
John R. Sult	(Principal Financial Officer)
/s/ Rosa P. Jackson	Vice President and Controller	February 28, 2011
Rosa P. Jackson	(Principal Accounting Officer)
/s/ Daniel B. Martin	Senior Vice President and Director	March 1, 2010
/s/ James C. Yardley
Daniel B. Martin
James C. Yardley	Chairman of the Board and Director	February 28, 2011
/s/ Bryan W. Neskora	Senior Vice President, Chief Commercial	March 1, 2010
/s/ Daniel B. Martin
Bryan W. Neskora	Officer and Director
Daniel B. Martin	Director	February 28, 2011
/s/ Bryan W. Neskora
Bryan W. Neskora	Director	February 28, 2011

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TENNESSEE GAS PIPELINE COMPANY

EXHIBIT INDEX

December 31, ~~2009~~2010

Each exhibit identified below is filed as part of this report. Exhibits filed with this report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit
Number	Description	~~Description~~
*3.A		Restated Certificate of Incorporation dated May 11, 1999.
3.A	Restated Certificate of Incorporation dated May 11, 1999 (incorporated by reference to Exhibit 3.A to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
3.B	By-laws dated as of June 2, 2008 (incorporated by reference to Exhibit 3.B to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).	~~By-laws dated as of June 2, 2008 (Exhibit 3.B to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 2, 2009).~~
4.A	Indenture dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).	Indenture dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (Exhibit 4.A to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
4.A.1	First Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).	First Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.1 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
4.A.2	Second Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).	Second Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.2 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
4.A.3	Third Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.3 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).	Third Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.3 to our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC on March 7, 2006).
4.A.4	Fourth Supplemental Indenture dated as of October 9, 1998, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.4 to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 7, 2006).	Fourth Supplemental Indenture dated as of October 9, 1998, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.4 to our Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 7, 2006).
4.A.5	Fifth Supplemental Indenture dated June 10, 2002, between Tennessee Gas Pipeline Company and the Trustee (incorporated by reference to Exhibit 4.A.5 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).	Fifth Supplemental Indenture dated June 10, 2002, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.5 to our Annual Report on Form 10-K for the year ended December 31, 2008, filed with the SEC on March 2, 2009).
4.A.6	Sixth Supplemental Indenture dated as of January 27, 2009 between Tennessee Gas Pipeline Company and Wilmington Trust Company, as trustee, to indenture dated as of March 4, 1997 (incorporated by reference to Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).	Sixth Supplemental Indenture dated as of January 27, 2009 between Tennessee Gas Pipeline Company and Wilmington Trust Company, as trustee, to indenture dated as of March 4, 1997 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).
10.A	Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (incorporated by reference to Exhibit 10.A to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010).

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*10.A		Third Amended and Restated Credit Agreement dated as of November 16, 2007, among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent.
10.B	Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (incorporated by reference to Exhibit 10.B to our Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on March 1, 2010).
*10.B		Third Amended and Restated Security Agreement dated as of November 16, 2007, made by among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank.
10.C	Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (incorporated by reference to Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007).
10.C		Third Amended and Restated Subsidiary Guarantee Agreement dated as of November 16, 2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Current Report on Form 8-K filed with the SEC on November 21, 2007).
10.D	Registration Rights Agreement, dated as of January 27, 2009, among Tennessee Gas Pipeline Company and Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Greenwich Capital Markets, Inc., BMO Capital Markets Corp., BNP Paribas Securities Corp., SG Americas Securities, LLC, UBS Securities LLC, and Wells Fargo Securities, LLC (incorporated by reference to Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).
10.D		Registration Rights Agreement, dated as of January 27, 2009, among Tennessee Gas Pipeline Company and Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Greenwich Capital Markets, Inc., BMO Capital Markets Corp., BNP Paribas Securities Corp., SG Americas Securities, LLC, UBS Securities LLC, and Wells Fargo Securities, LLC (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on January 29, 2009).
21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
*12		Ratio of Earnings to Fixed Charges.
*23	Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.
21		Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
*31.A	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*23		Consent of Independent Registered Public Accounting Firm Ernst & Young LLP.
*31.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.A		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.A	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*31.B		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.A		Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.B		Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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